10-Q

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED   June 30, 2013

OR

¨ 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, Nevada89146
	(702) 402-5000
2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada89146
	(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, Nevada89520-0400 (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 website, 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  þ           No  o     (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 the definitions 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 Exchange 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 July 31, 2013
Common Stock, $1.00 par value of NV Energy, Inc.	235,580,598 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.

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Acronyms & Terms				3
ITEM 1.	Financial Statements
	NV Energy, Inc.
			Consolidated Statements of Comprehensive Income  – Three and Six Months Ended June 30, 2013 and 2012	5
			Consolidated Balance Sheets – June 30, 2013 and December 31, 2012	6
			Consolidated Statements of Cash Flows -  Six Months Ended June 30, 2013 and 2012	8
			Consolidated Statements of Shareholders’ Equity -  Six Months Ended June 30, 2013 and 2012	9
	Nevada Power Company
			Consolidated Statements of Comprehensive Income   –  Three and Six  Months Ended June 30, 2013 and 2012	10
			Consolidated Balance Sheets – June 30, 2013 and December 31, 2012	11
			Consolidated Statements of Cash Flows -   Six Months Ended June 30, 2013  and 2012	13
			Consolidated Statements of Shareholder’s Equity - Six  Months Ended June 30, 2013 and 2012	14
	Sierra Pacific Power Company
			Consolidated Statements of Comprehensive Income   –  Three and Six  Months Ended June 30, 2013 and 2012	15
			Consolidated Balance Sheets – June 30, 2013 and December 31, 2012	16
			Consolidated Statements of Cash Flows - Six  Months Ended June 30, 2013 and 2012	18
			Consolidated Statements of Shareholder’s Equity -  Six  Months Ended June 30, 2013 and 2012	19
	Condensed Notes to Financial Statements
			Note 1.     Summary of Significant Accounting Policies	20
			Note 2.     Merger Related Activities	20
			Note 3.     Segment Information	22
			Note 4.     Regulatory Actions	24
			Note 5.     Long-Term Debt	26
			Note 6.     Fair Value of Financial Instruments	27
			Note 7.     Retirement Plan and Post-Retirement Benefits	27
			Note 8.     Commitments and Contingencies	28
			Note 9.     Earnings per Share (NVE)	32
			Note 10.   Common Stock and Other Paid-In Capital	32
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
	NV Energy, Inc.			38
	Nevada Power Company			41
	Sierra Pacific Power Company			47
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk			55
ITEM 4.	Controls and Procedures			55
PART II – OTHER INFORMATION
ITEM 1.		Legal Proceedings		56
ITEM 1A.		Risk Factors		56
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds		57
ITEM 3.		Defaults Upon Senior Securities		57
ITEM 4.		Mine Safety Disclosures		57
ITEM 5.		Other Information		57
ITEM 6.		Exhibits		58
Signature Page and Certifications				60

2

ACRONYMS AND TERMS

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

Acronym/Term	Meaning
2012 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CA ISO	California Independent System Operator Corporation
California Assets	SPPC's California electric distribution and generation assets
CalPeco	California Pacific Electric Company
CDD	Cooling degree days
CDWR	California Department of Water Resources
CIAC	Contributions in Aid of Construction
CWIP	Construction Work-in-Progress
dba	Doing business as
DEAA	Deferred Energy Accounting Adjustment
Dth	Decatherm
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
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.
Ft. Churchill Generating Station	226 megawatt nominally rated Fort Churchill Generating Station
GAAP	Generally Accepted Accounting Principles in the United States
GBT	Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC
GBT-South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
GRC	General Rate Case
Harry Allen Generating Station	642 megawatt nominally rated Harry Allen Generating Station
HDD	Heating degree days
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP	Integrated resource plan
kV	Kilovolt
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
MEHC	MidAmerican Energy Holdings Company, an Iowa corporation, and subsidiary of Berkshire Hathaway, Inc.
MidAmerican Merger	The merger contemplated by the MidAmerican Merger Agreement of Silver Merger Sub, Inc., a Nevada corporation
	and wholly-owned subsidiary of MEHC, with and into NVE, with NVE continuing as the surviving corporation.
MidAmerican Merger Agreement	The agreement and plan of merger dated as of May 29, 2013, among NVE, MEHC and Silver Merger Sub, Inc., a Nevada
	corporation and wholly-owned subsidiary of MEHC
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 Electric Investment Company
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NOL	Net Operating Loss
NPC	Nevada Power Company d/b/a NV Energy
NPC Credit Agreement	$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,
	N.A., as administrative agent for the lenders a party thereto
NPC 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
NRSRO	Nationally Recognized Statistical Rating Organization
NVE	NV Energy, Inc.

3

NV Energize	A smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will provide
	customers the ability to more directly manage their energy usage
NVEOC	NV Energy Operating Company
NVision	A comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the
	accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with
	increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further
	demand response programs
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
One Company Merger	The merger between NPC and SPPC, whereby SPPC will be merged into NPC and the surviving entity will be called NVEOC
Portfolio Standard	Nevada Renewable Energy Portfolio Standard
PUCN	Public Utilities Commission of Nevada
Reid Gardner Generating Station	325 megawatt nominally rated Reid Gardner Generating Station
REPR	Renewable Energy Program Rate
ROR	Rate of return
SB 123	Senate Bill 123 passed into law by the Nevada State Legislature in June 2013, requiring certain electric utilities in
	Nevada to file with the PUCN an emissions reduction and capacity replacement plan; and prescribing the minimum
	requirements of such a plan
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
Smart Meters	Advanced service delivery meters installed as part of the NV Energize project
SNWA	Southern Nevada Water Authority
SPPC	Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement	$250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells Fargo
	Bank, N.A., as administrative agent for the lenders a party thereto
SPPC 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
STPR	Solar Thermal Program Rate
Term Loan	$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank,
	N.A., as administrative agent for the lenders a party thereto
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 megawatt nominally rated Frank A. Tracy Generating Station
TRED	Temporary Renewable Energy Development
TUA	Transmission Use and Capacity Exchange Agreement with GBT-South
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
VIE	Variable Interest Entity
WSPP	Western Systems Power Pool

4

ITEM 1.                        FINANCIAL STATEMENTS

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
OPERATING REVENUES		$	731,638	$	740,698	$	1,315,860	$	1,352,118
OPERATING EXPENSES:
	Fuel for power generation		188,979		112,585		336,227		229,620
	Purchased power		170,861		164,092		292,171		281,208
	Gas purchased for resale		17,274		9,492		54,894		41,109
	Deferred energy		(86,687)		10,490		(165,752)		(1,249)
	Energy efficiency program costs		12,599		24,600		22,444		44,025
	Merger related costs (Note 2)		13,552		-		13,552		-
	Other operating expenses		106,798		103,371		211,470		206,972
	Maintenance		24,046		24,650		48,952		57,176
	Depreciation and amortization		98,884		96,316		194,886		187,178
	Taxes other than income		15,846		14,266		32,322		28,775
Total Operating Expenses			562,152		559,862		1,041,166		1,074,814
OPERATING INCOME			169,486		180,836		274,694		277,304
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,682 , $1,908 , $3,813 and $3,503)		(73,530)		(74,564)		(146,867)		(152,495)
	Interest income (expense) on regulatory items		(16)		(1,977)		(843)		(4,179)
	AFUDC-equity		2,250		2,319		5,139		4,251
	Other income		3,813		6,291		7,633		10,485
	Other expense		(4,036)		(4,640)		(8,287)		(7,700)
Total Other Income (Expense)			(71,519)		(72,571)		(143,225)		(149,638)
Income Before Income Tax Expense			97,967		108,265		131,469		127,666
Income tax expense			34,734		38,826		46,761		46,054
NET INCOME			63,233		69,439		84,708		81,612
Other comprehensive income (loss)
Change in compensation retirement benefits liability and amortization
(Net of taxes $(129), $(83), $(265) and $(172))			246		154		492		309
Change in market value of risk management assets and liabilities
(Net of taxes $3, $123, $(107) and $264)			297		(229)		496		(475)
Unrealized net gain/(loss) on investment
(Net of taxes $31, $0, $31 and $0)			(65)		-		(65)		-
OTHER COMPREHENSIVE INCOME (LOSS)			478		(75)		923		(166)
COMPREHENSIVE INCOME		$	63,711	$	69,364	$	85,631	$	81,446
Amount per share basic and diluted (Note 9)
	Net income per share - basic	$	0.27	$	0.29	$	0.36	$	0.35
	Net income per share - diluted	$	0.27	$	0.29	$	0.36	$	0.34
Weighted Average Shares of Common Stock Outstanding - basic			235,489,559		235,999,750		235,342,448		235,999,750
Weighted Average Shares of Common Stock Outstanding - diluted			237,401,400		237,903,276		237,204,505		237,715,070
Dividends Declared Per Share of Common Stock		$	0.19	$	0.17	$	0.38	$	0.30
The accompanying notes are an integral part of the financial statements.

5

NV ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			June 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	261,068	$	298,271
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $7,150; 2012 - $8,748		433,336		373,099
	Materials, supplies and fuel, at average cost			130,747		138,337
	Deferred energy costs - electric (Note 4)			30,122		-
	Deferred energy costs - gas (Note 4)			991		-
	Deferred income taxes			109,450		60,592
	Other current assets			47,591		40,750
Total Current Assets				1,013,305		911,049
Utility Property:
	Plant in service			12,159,227		12,031,053
	Construction work-in-progress			757,924		708,109
	Total			12,917,151		12,739,162
Less accumulated provision for depreciation				3,448,469		3,313,188
	Total Utility Property, Net			9,468,682		9,425,974
Investments and other property, net				63,387		56,660
Deferred Charges and Other Assets:
	Deferred energy (Note 4)			81,274		87,072
	Regulatory assets			1,077,364		1,132,768
	Regulatory asset for pension plans			274,200		281,195
	Other deferred charges and assets			75,029		89,418
Total Deferred Charges and Other Assets				1,507,867		1,590,453
TOTAL ASSETS			$	12,053,241	$	11,984,136
		(Continued)

6

		NV ENERGY, INC.
		CONSOLIDATED BALANCE SHEETS
		(Dollars in Thousands, Except Share Amounts)
		(Unaudited)
			June 30,		December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY			2013		2012
Current Liabilities:
	Current maturities of long-term debt (Note 5)		$	480,018	$	356,283
	Accounts payable			333,588		332,245
	Accrued expenses			119,245		127,693
	Deferred energy (Note 4)			-		136,865
	Other current liabilities			69,895		66,221
Total Current Liabilities				1,002,746		1,019,307
Long-term debt (Note 5)				4,543,733		4,669,798
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes			1,564,260		1,470,973
	Deferred investment tax credit			12,430		13,538
	Accrued retirement benefits			167,793		162,260
	Regulatory liabilities			583,217		550,687
	Other deferred credits and liabilities			614,873		540,202
Total Deferred Credits and Other Liabilities				2,942,573		2,737,660
Shareholders' Equity:
	Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued
		for 2013 and 2012; 235,546,924 and 235,079,156 outstanding for 2013 and 2012, respectively		236,000		236,000
	Treasury stock at cost, 452,826 shares and 920,594 shares for 2013 and 2012, respectively			(8,542)		(16,804)
	Other paid-in capital			2,715,358		2,712,943
	Retained earnings			630,521		635,303
	Accumulated other comprehensive loss			(9,148)		(10,071)
Total Shareholders' Equity				3,564,189		3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	12,053,241	$	11,984,136
The accompanying notes are an integral part of the financial statements.
(Concluded)

7

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Six Months Ended
			June 30,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	84,708	$	81,612
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		194,886		187,178
		Deferred taxes and deferred investment tax credit		46,599		34,425
		AFUDC-equity		(5,139)		(4,251)
		Deferred energy		(162,179)		6,888
		Amortization of other regulatory assets		85,882		75,711
		Deferred rate increase		4,602		2,474
		Other, net		6,769		2,279
	Changes in certain assets and liabilities:
		Accounts receivable		(51,238)		(79,520)
		Materials, supplies and fuel		7,771		(16,594)
		Other current assets		(6,548)		1,518
		Accounts payable		21,621		4,493
		Accrued retirement benefits		5,533		4,907
		Other current liabilities		(4,535)		(4,875)
		Other deferred assets		(2,400)		(2,700)
		Other regulatory assets		(4,374)		10,058
		Other deferred liabilities		6,185		(10,940)
Net Cash from Operating Activities				228,143		292,663
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(191,673)		(261,559)
		Customer advances for construction		149		(847)
		Contributions in aid of construction		27,975		45,106
		Investments and other property - net		(5,005)		(128)
Net Cash used by Investing Activities				(168,554)		(217,428)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		(312)		130,590
		Retirement of long-term debt		(2,459)		(158,201)
		Sale of common stock		1,798		-
		Common stock repurchased		(6,329)		-
		Dividends paid		(89,490)		(70,800)
Net Cash used by Financing Activities				(96,792)		(98,411)
Net Decrease in Cash and Cash Equivalents				(37,203)		(23,176)
Beginning Balance in Cash and Cash Equivalents				298,271		145,944
Ending Balance in Cash and Cash Equivalents			$	261,068	$	122,768
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	143,592	$	148,603
		Income taxes	$	2	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of June 30,	$	107,466	$	121,785
		Issuance of treasury stock	$	12,793	$	-
The accompanying notes are an integral part of the financial statements.

8

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

												Accumulated
		Common	Common		Treasury		Treasury	Other				Other		Total
		Stock	Stock		Stock		Stock	Paid-in		Retained		Comprehensive		Shareholders'
		Shares	Amount		Shares		Amount	Capital		Earnings		Income (Loss)		Equity
December 31, 2011		235,999,750	$	236,000	-	$	-	$	2,713,736	$	464,277	$	(7,934)	$	3,406,079
	Net Income	-		-	-		-		-		81,612		-		81,612
	Change in compensation retirement benefits
	liability and amortization (net of taxes $(172))	-		-	-		-		-		-		309		309
	Change in market value of risk management
	assets and liabilities (net of taxes $ 264)	-		-	-		-		-		-		(475)		(475)
	Dividends Declared	-		-	-		-		-		(70,800)		-		(70,800)
June 30, 2012		235,999,750	$	236,000	-	$	-	$	2,713,736	$	475,089	$	(8,100)	$	3,416,725
December 31, 2012		235,999,750	$	236,000	(920,594)	$	(16,804)	$	2,712,943	$	635,303	$	(10,071)	$	3,557,371
	Net Income	-		-	-		-		-		84,708		-		84,708
	Employee Benefits	-		-	792,946		14,591		2,415		-		-		17,006
	Change in compensation retirement benefits
	liability and amortization (net of taxes $(265))	-		-	-		-		-		-		492		492
	Change in market value of risk management
	assets and liabilities (net of taxes $(107))	-		-	-		-		-		-		496		496
	Unrealized net gain/(loss) on investment
	(net of taxes $31)	-		-	-		-		-		-		(65)		(65)
	Common stock repurchased	-		-	(325,178)		(6,329)		-		-		-		(6,329)
	Dividends Declared	-		-	-		-		-		(89,490)		-		(89,490)
June 30, 2013		235,999,750	$	236,000	(452,826)	$	(8,542)	$	2,715,358	$	630,521	$	(9,148)	$	3,564,189
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
OPERATING REVENUES		$	537,124	$	553,143	$	908,987	$	948,831
OPERATING EXPENSES:
	Fuel for power generation		144,246		81,258		249,777		161,807
	Purchased power		129,396		135,276		210,804		216,807
	Deferred energy		(63,748)		5,053		(109,103)		7,224
	Energy efficiency program costs		10,842		21,200		18,809		36,974
	Merger related costs (Note 2)		8,867		-		8,867		-
	Other operating expenses		70,100		68,650		137,492		135,112
	Maintenance		15,889		16,988		33,964		40,061
	Depreciation and amortization		70,405		69,131		139,066		134,121
	Taxes other than income		9,632		8,596		19,591		17,050
Total Operating Expenses			395,629		406,152		709,267		749,156
OPERATING INCOME			141,495		146,991		199,720		199,675
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,406, $1,314, $3,243 and $2,493)		(51,643)		(52,602)		(102,902)		(107,007)
	Interest income (expense) on regulatory items		(181)		(1,849)		(983)		(3,865)
	AFUDC-equity		1,826		1,577		4,192		2,990
	Other income		978		5,392		3,382		7,101
	Other expense		(1,833)		(2,993)		(4,234)		(4,339)
Total Other Income (Expense)			(50,853)		(50,475)		(100,545)		(105,120)
Income Before Income Tax Expense			90,642		96,516		99,175		94,555
Income tax expense			31,977		34,219		35,065		33,574
NET INCOME			58,665		62,297		64,110		60,981
Other comprehensive income
Change in compensation retirement benefits liability and amortization
(Net of taxes $(50), $(38), $(104) and $(70))			97		64		194		127
COMPREHENSIVE INCOME		$	58,762	$	62,361	$	64,304	$	61,108
The accompanying notes are an integral part of the financial statements.

10

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			June 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	141,686	$	201,202
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $6,211; 2012 - $7,622		323,870		248,501
	Materials, supplies and fuel, at average cost			77,488		77,675
	Deferred energy  (Note 4)			27,389		-
	Deferred income taxes			86,367		48,590
	Other current assets			35,102		28,763
Total Current Assets				691,902		604,731
Utility Property:
	Plant in service			8,437,303		8,363,566
	Construction work-in-progress			649,128		567,941
		Total		9,086,431		8,931,507
	Less accumulated provision for depreciation			2,143,914		2,035,322
		Total Utility Property, Net		6,942,517		6,896,185
Investments and other property, net				50,027		49,808
Deferred Charges and Other Assets:
	Deferred energy (Note 4)			80,109		87,072
	Regulatory assets			762,681		804,013
	Regulatory asset for pension plans			133,409		136,682
	Other deferred charges and assets			58,959		62,654
Total Deferred Charges and Other Assets				1,035,158		1,090,421
TOTAL ASSETS			$	8,719,604	$	8,641,145
(Continued)

11

		NEVADA POWER COMPANY
		CONSOLIDATED BALANCE SHEETS
		(Dollars in Thousands, Except Share Amounts)
		(Unaudited)
			June 30,		December 31,
			2013		2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 5)		$	229,743	$	106,048
	Accounts payable			212,133		201,193
	Accounts payable, affiliated companies			48,398		42,036
	Accrued expenses			82,199		86,433
	Deferred energy (Note 4)			-		86,102
	Other current liabilities			55,326		52,567
Total Current Liabilities				627,799		574,379
Long-term debt (Note 5)				3,104,936		3,230,808
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes			1,173,431		1,101,804
	Deferred investment tax credit			4,126		4,688
	Accrued retirement benefits			51,418		49,381
	Regulatory liabilities			343,521		323,400
	Other deferred credits and liabilities			507,751		434,367
Total Deferred Credits and Other Liabilities				2,080,247		1,913,640
Shareholder's Equity:
	Common stock, $1.00 par value; 1,000 shares authorized
		issued and outstanding for 2013 and 2012		1		1
	Other paid-in capital			2,308,211		2,308,211
	Retained earnings			602,722		618,612
	Accumulated other comprehensive loss			(4,312)		(4,506)
Total Shareholder's Equity				2,906,622		2,922,318
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	8,719,604	$	8,641,145
The accompanying notes are an integral part of the financial statements.
(Concluded)

12

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Six Months Ended
			June 30,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	64,110	$	60,981
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		139,066		134,121
		Deferred taxes and deferred investment tax credit		34,800		27,209
		AFUDC-equity		(4,192)		(2,990)
		Deferred energy		(106,527)		13,127
		Amortization of other regulatory assets		47,490		36,659
		Deferred rate increase		4,602		2,474
		Other, net		769		(213)
	Changes in certain assets and liabilities:
		Accounts receivable		(75,369)		(101,041)
		Materials, supplies and fuel		368		(4,167)
		Other current assets		(6,340)		3,159
		Accounts payable		30,467		41,388
		Accrued retirement benefits		2,037		2,605
		Other current liabilities		(1,238)		(3,342)
		Other deferred assets		(990)		(1,973)
		Other regulatory assets		(1,004)		24,720
		Other deferred liabilities		541		(6,386)
Net Cash from Operating Activities				128,590		226,331
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(117,291)		(164,634)
		Customer advances for construction		198		637
		Contributions in aid of construction		10,118		25,383
		Investments and other property - net		1,196		(144)
Net Cash used by Investing Activities				(105,779)		(138,758)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		(147)		132,083
		Retirement of long-term debt		(2,180)		(157,491)
		Dividends paid		(80,000)		(79,000)
Net Cash used by Financing Activities				(82,327)		(104,408)
Net Decrease in Cash and Cash Equivalents				(59,516)		(16,835)
Beginning Balance in Cash and Cash Equivalents				201,202		65,887
Ending Balance in Cash and Cash Equivalents			$	141,686	$	49,052
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	101,242	$	105,973
		Income taxes	$	1	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of June 30,	$	86,745	$	98,358
The accompanying notes are an integral part of the financial statements.

13

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2011		1,000	$	1	$	2,308,219	$	544,874	$	(4,117)	$	2,848,977
	Net Income	-		-		-		60,981		-		60,981
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(70))	-		-		-		-		127		127
	Dividends Declared	-		-		-		(79,000)		-		(79,000)
June 30, 2012		1,000	$	1	$	2,308,219	$	526,855	$	(3,990)	$	2,831,085
December 31, 2012		1,000	$	1	$	2,308,211	$	618,612	$	(4,506)	$	2,922,318
	Net Income	-		-		-		64,110		-		64,110
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(104))	-		-		-		-		194		194
	Dividends Declared	-		-		-		(80,000)		-		(80,000)
June 30, 2013		1,000	$	1	$	2,308,211	$	602,722	$	(4,312)	$	2,906,622
The accompanying notes are an integral part of the financial statements.

14

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
OPERATING REVENUES:
	Electric	$	174,302	$	168,007	$	346,929	$	337,813
	Gas		20,208		19,544		59,937		65,466
Total Operating Revenues			194,510		187,551		406,866		403,279
OPERATING EXPENSES:
	Fuel for power generation		44,733		31,327		86,450		67,813
	Purchased power		41,465		28,816		81,367		64,401
	Gas purchased for resale		17,274		9,492		54,894		41,109
	Deferred energy - electric - net (Note 4)		(16,963)		4,314		(36,298)		(8,356)
	Deferred energy - gas - net (Note 4)		(5,976)		1,123		(20,351)		(117)
	Energy efficiency program costs		1,757		3,400		3,635		7,051
	Merger related costs (Note 2)		3,520		-		3,520		-
	Other operating expenses		36,256		33,654		72,061		70,086
	Maintenance		8,157		7,662		14,988		17,115
	Depreciation and amortization		28,479		27,185		55,820		53,057
	Taxes other than income		6,175		5,625		12,470		11,488
Total Operating Expenses			164,877		152,598		328,556		323,647
OPERATING INCOME			29,633		34,953		78,310		79,632
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $276, $594, $570 and $1,010)		(15,373)		(15,379)		(30,898)		(32,352)
	Interest income (expense) on regulatory items		165		(128)		140		(314)
	AFUDC-equity		424		742		947		1,261
	Other income		2,518		599		3,658		2,782
	Other expense		(1,573)		(1,276)		(2,821)		(2,611)
Total Other Income (Expense)			(13,839)		(15,442)		(28,974)		(31,234)
Income Before Income Tax Expense			15,794		19,511		49,336		48,398
Income tax expense			5,018		6,832		16,656		17,075
NET INCOME			10,776		12,679		32,680		31,323
Other comprehensive income
Change in compensation retirement benefits liability and amortization
(Net of taxes $(32), $(23), $(63) and $(46))			58		43		117		85
COMPREHENSIVE INCOME		$	10,834	$	12,722	$	32,797	$	31,408
The accompanying notes are an integral part of the financial statements.

15

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			June 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	91,950	$	60,786
	Accounts receivable less allowance for uncollectible accounts:
	2013 - $939; 2012 - $1,126			109,324		124,464
	Materials, supplies and fuel, at average cost			53,259		60,662
	Deferred energy - electric (Note 4)			2,733		-
	Deferred energy - gas (Note 4)			991		-
	Intercompany income taxes receivable			10,351		10,351
	Deferred income taxes			33,190		21,589
	Other current assets			11,799		11,633
Total Current Assets				313,597		289,485
Utility Property:
	Plant in service			3,721,924		3,667,487
	Construction work-in-progress			108,796		140,168
		Total		3,830,720		3,807,655
	Less accumulated provision for depreciation			1,304,555		1,277,866
		Total Utility Property, Net		2,526,165		2,529,789
Investments and other property, net				6,792		6,499
Deferred Charges and Other Assets:
	Regulatory assets			314,683		328,755
	Regulatory asset for pension plans			137,050		140,268
	Deferred energy - gas (Note 4)			1,165		-
	Other deferred charges and assets			10,790		21,477
Total Deferred Charges and Other Assets				463,688		490,500
TOTAL ASSETS			$	3,310,242	$	3,316,273
(Continued)

16

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
			June 30,		December 31,
			2013		2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 5)		$	250,275	$	250,235
	Accounts payable			85,323		106,415
	Accounts payable, affiliated companies			28,209		21,534
	Accrued expenses			30,990		32,936
	Deferred energy (Note 4)			-		50,763
	Other current liabilities			14,570		13,655
Total Current Liabilities				409,367		475,538
Long-term debt (Note 5)				928,797		928,990
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes			492,443		465,508
	Deferred investment tax credit			8,304		8,850
	Accrued retirement benefits			99,732		98,676
	Regulatory liabilities			239,696		227,287
	Other deferred credits and liabilities			80,370		72,688
Total Deferred Credits and Other Liabilities				920,545		873,009
Shareholder's Equity:
	Common stock, $3.75 par value; 20,000,000 shares authorized
		1,000 shares issued and outstanding for 2013 and 2012		4		4
	Other paid-in capital			1,111,266		1,111,266
	Retained deficit			(58,306)		(70,986)
	Accumulated other comprehensive loss			(1,431)		(1,548)
Total Shareholder's Equity				1,051,533		1,038,736
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	3,310,242	$	3,316,273
The accompanying notes are an integral part of the financial statements.
(Concluded)

17

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Six Months Ended
			June 30,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	32,680	$	31,323
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		55,820		53,057
		Deferred taxes and deferred investment tax credit		16,759		11,894
		AFUDC-equity		(947)		(1,261)
		Deferred energy		(55,652)		(6,239)
		Amortization of other regulatory assets		38,270		38,957
		Other, net		3,171		1,772
	Changes in certain assets and liabilities:
		Accounts receivable		24,140		21,543
		Materials, supplies and fuel		7,403		(12,427)
		Other current assets		127		(1,285)
		Accounts payable		(7,303)		(27,583)
		Accrued retirement benefits		1,056		936
		Other current liabilities		(1,030)		(1,251)
		Other deferred assets		(1,410)		(727)
		Other regulatory assets		(3,370)		(14,662)
		Other deferred liabilities		(1,548)		(3,173)
Net Cash from Operating Activities				108,166		90,874
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(74,382)		(96,925)
		Customer advances for construction		(49)		(1,484)
		Contributions in aid of construction		17,857		19,723
		Investments and other property - net		16		16
Net Cash used by Investing Activities				(56,558)		(78,670)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		(165)		(1,446)
		Retirement of long-term debt		(279)		(710)
		Dividends paid		(20,000)		(20,000)
Net Cash used by Financing Activities				(20,444)		(22,156)
Net Increase (Decrease) in Cash and Cash Equivalents				31,164		(9,952)
Beginning Balance in Cash and Cash Equivalents				60,786		55,195
Ending Balance in Cash and Cash Equivalents			$	91,950	$	45,243
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	29,757	$	30,000
	Significant non-cash transactions:
		Accrued construction expenses as of June 30,	$	20,721	$	23,427
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-In		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Deficit		Income (Loss)		Equity
December 31, 2011		1,000	$	4	$	1,111,262	$	(135,340)	$	(1,384)	$	974,542
	Net Income	-		-		-		31,323		-		31,323
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(46))	-		-		-		-		85		85
	Dividends Declared	-		-		-		(20,000)		-		(20,000)
June 30, 2012		1,000	$	4	$	1,111,262	$	(124,017)	$	(1,299)	$	985,950
December 31, 2012		1,000	$	4	$	1,111,266	$	(70,986)	$	(1,548)	$	1,038,736
	Net Income	-		-		-		32,680		-		32,680
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(63))	-		-		-		-		117		117
	Dividends Declared	-		-		-		(20,000)		-		(20,000)
June 30, 2013		1,000	$	4	$	1,111,266	$	(58,306)	$	(1,431)	$	1,051,533
The accompanying notes are an integral part of the financial statements.

19

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE1.     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, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., 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 2012 Form 10-K.

                        The results of operations and cash flows of NVE, NPC and SPPC for the six months ended June 30, 2013, are not necessarily indicative of the results to be expected for the full year.

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests.  However, the Utilities are not the primary beneficiary 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 June 30, 2013, 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.

Recent Accounting Standards Update

Derivatives and Hedging (ASC815) 

In July 2013, the FASB amended its existing guidance related to hedge accounting.  The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR.  The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013.    NVE and the Utilities do not expect this amendment to have a material impact on their financial statements or disclosure requirements.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements.  FASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists.  As a result, there is diversity in practice in the presentation of unrecognized tax benefits.  The objective of the amendment is to eliminate the diversity in practice, requiring the unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions.  The amendment will be applied prospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities are evaluating the potential effects of this amendment and currently do not anticipate that the adoption of this amendment will have a material impact on the presentation of NVE and the Utilities’ consolidated financial statements.   

      Other Comprehensive Income (ASC 220)

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income.  In February 2013, the FASB reinstated certain portions of the deferred amendment.  The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

      Balance Sheet Offsetting Disclosures (ASC 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements.  The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position.  The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have a material impact on the disclosure requirements for NVE and the Utilities.

NOTE2.      MERGER RELATED ACTIVITIES

MidAmerican Merger

On May 29, 2013, NVE entered into the MidAmerican Merger Agreement.  The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation in the MidAmerican Merger.  Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.  The closing is expected to occur during the first quarter of 2014.

Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest and subject to applicable withholding taxes. 

20

`                       The MidAmerican Merger Agreement has been approved by the BOD of both NVE and MEHC, but the consummation of the MidAmerican Merger is subject to the satisfaction or waiver of specified closing conditions, including:

• the approval of the MidAmerican Merger by the holders of a majority of the outstanding shares of NVE common stock (NVE filed a preliminary proxy statement with the SEC in July 2013);

• the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC.  See Note 4, Regulatory Actions, for further details of these filings);

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.  On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission had terminated the applicable waiting period under the Hart-Scott-Rodino Act.  Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied;

• the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and

• other customary closing conditions.

The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions,to conduct our business in a manner substantially consistent with our current practice.  In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances or limitations on increasing our common stock dividend payout. 

The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC.  In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.

During the three and six month periods ending June 30, 2013, NVE incurred $13.6 million (pre-tax) of merger related fees and stock compensation costs related to the MidAmerican Merger which have been expensed and presented on the Statement of Comprehensive Income as Merger Related Costs.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation, upon announcement of the MidAmerican Merger.  NVE expects to incur additional merger fees relating to the MidAmerican Merger, as well as, upon consummation of the MidAmerican Merger.

As a result of the pending MidAmerican Merger, NVE, its directors, Silver Merger Sub, Inc. and, in some cases, MEHC, have been named as defendants in certain lawsuits brought by alleged NVE shareholders seeking, among other things, to enjoin the proposed MidAmerican Merger; see Note 8, Commitments and Contingencies for further details.  In addition, NVE has ceased the repurchase of any common stock for NVE stock compensation plans; see Note 10, Common Stock and Other Paid-In Capital. 

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities.  As a result, NVE, NPC and SPPC will be required to offer for purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under these debt securities is approximately 6.25%, 6.42% and 6.05% for NVE, NPC and SPPC, respectively.  To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities are required to obtain consents from lenders under the terms of the Utilities’ revolving credit facilities and NVE’s term loan before consummating the MidAmerican Merger.

One Company Merger between NPC and SPPC

As detailed further in Note 4, Regulatory Actions, NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC.   The One Company Merger is subject to approval by the PUCN and FERC.

21

NOTE 3.SEGMENT INFORMATION

The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC.  Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada 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 and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities.  See Note 1, Summary of Significant Accounting Policies,of the Notes to Financial Statements in the 2012 Form 10-K for further information regarding energy efficiency program costs.  

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
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	731,638	$	4	$	537,124	$	194,510	$	174,302	$	20,208
Energy Costs:
	Fuel for power generation		188,979		-		144,246		44,733		44,733		-
	Purchased power		170,861		-		129,396		41,465		41,465		-
	Gas purchased for resale		17,274		-		-		17,274		-		17,274
	Deferred energy		(86,687)		-		(63,748)		(22,939)		(16,963)		(5,976)
Energy efficiency program costs			12,599		-		10,842		1,757		1,757		-
Total Costs		$	303,026	$	-	$	220,736	$	82,290	$	70,992	$	11,298
Gross Margin		$	428,612	$	4	$	316,388	$	112,220	$	103,310	$	8,910
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			106,798		442		70,100		36,256
Maintenance			24,046		-		15,889		8,157
Depreciation and amortization			98,884		-		70,405		28,479
Taxes other than income			15,846		39		9,632		6,175
Operating Income (Loss)		$	169,486	$	(1,642)	$	141,495	$	29,633

Six Months Ended
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,315,860	$	7	$	908,987	$	406,866	$	346,929	$	59,937
Energy Costs:
	Fuel for power generation		336,227		-		249,777		86,450		86,450		-
	Purchased power		292,171		-		210,804		81,367		81,367		-
	Gas purchased for resale		54,894		-		-		54,894		-		54,894
	Deferred energy		(165,752)		-		(109,103)		(56,649)		(36,298)		(20,351)
Energy efficiency program costs			22,444		-		18,809		3,635		3,635		-
Total Costs		$	539,984	$	-	$	370,287	$	169,697	$	135,154	$	34,543
Gross Margin		$	775,876	$	7	$	538,700	$	237,169	$	211,775	$	25,394
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			211,470		1,917		137,492		72,061
Maintenance			48,952		-		33,964		14,988
Depreciation and amortization			194,886		-		139,066		55,820
Taxes other than income			32,322		261		19,591		12,470
Operating Income (Loss)		$	274,694	$	(3,336)	$	199,720	$	78,310

22

Three Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	740,698	$	4	$	553,143	$	187,551	$	168,007	$	19,544
Energy Costs:
	Fuel for power generation		112,585		-		81,258		31,327		31,327		-
	Purchased power		164,092		-		135,276		28,816		28,816		-
	Gas purchased for resale		9,492		-				9,492		-		9,492
	Deferred energy		10,490		-		5,053		5,437		4,314		1,123
Energy efficiency program costs			24,600		-		21,200		3,400		3,400		-
Total Costs		$	321,259	$	-	$	242,787	$	78,472	$	67,857	$	10,615
Gross Margin		$	419,439	$	4	$	310,356	$	109,079	$	100,150	$	8,929
Other operating expenses			103,371		1,067		68,650		33,654
Maintenance			24,650		-		16,988		7,662
Depreciation and amortization			96,316		-		69,131		27,185
Taxes other than income			14,266		45		8,596		5,625
Operating Income (Loss)		$	180,836	$	(1,108)	$	146,991	$	34,953

Six Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,352,118	$	8	$	948,831	$	403,279	$	337,813	$	65,466
Energy Costs:
	Fuel for power generation		229,620		-		161,807		67,813		67,813		-
	Purchased power		281,208		-		216,807		64,401		64,401		-
	Gas purchased for resale		41,109		-		-		41,109		-		41,109
	Deferred Energy		(1,249)		-		7,224		(8,473)		(8,356)		(117)
Energy efficiency program costs			44,025		-		36,974		7,051		7,051		-
Total Costs		$	594,713	$	-	$	422,812	$	171,901	$	130,909	$	40,992
Gross Margin		$	757,405	$	8	$	526,019	$	231,378	$	206,904	$	24,474
Other operating expenses			206,972		1,774		135,112		70,086
Maintenance			57,176		-		40,061		17,115
Depreciation and amortization			187,178		-		134,121		53,057
Taxes other than income			28,775		237		17,050		11,488
Operating Income (Loss)		$	277,304	$	(2,003)	$	199,675	$	79,632

23

NOTE 4.REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 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 June 30, 2013 (dollars in thousands):

		June 30, 2013
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance as of December 31, 2012	$	(151,880)	$	(101,117)	$	(32,693)	$	(18,070)
	2013 Amortization		94,134		57,887		19,196		17,051
	2013 Deferred Energy Under Collections  (1)		75,030		55,625		16,230		3,175
Deferred Energy Balance at June 30, 2013 - Subtotal		$	17,284	$	12,395	$	2,733	$	2,156
Reinstatement of deferred energy (effective 6/07, 10 years)			95,103		95,103		-		-
	Total Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
Current Assets
	Deferred energy	$	31,113	$	27,389	$	2,733	$	991
Non-current Assets
	Deferred energy		81,274		80,109		-		1,165
	Total Net Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
(1)	These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting
	Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Joint Application for the merger between NVE and MEHC (MidAmerican Merger)

In July 2013, NVE and MEHC filed a joint application with the PUCN seeking the authorization of NVE’s merger with MEHC. Under Nevada law, the PUCN may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “in the public interest.”  If the PUCN does not issue a final order regarding the MidAmerican Merger within 180 days of the application filing date, the transaction will be deemed to be authorized.  Based on the date of filing, the expected authorization date for the joint application between NVE and MEHC is January 2014. 

      Joint Application of NPC and SPPC (One Company Merger Filing)

In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility.  The joint application with the PUCN requested the following:

• Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility NVEOC;

• Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and

• Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”Hearings are expected to begin in February 2014.

      Financing Application

Concurrent with the One Company Merger filing, NPC and SPPC filed a joint financing application with the PUCN.  The application requested the PUCN to restate and review the Utilities’ existing unused authority and to assign and consolidate the unused authority under NVEOC.  In addition, the application requests new authority of $705.0 million.  The consolidated authority would give NVEOC authority to issue new debt of $1.1 billion and authority to refinance or redeem debt of $1.5 billion. The application does not seek a change to NPC’s and SPPC’s existing revolving credit facility authority of $1.3 billion and $600 million, respectively.   The Utilities have requested that the financing application be consolidated with the One Company Merger filing.  However, as the One Company Merger will not be approved prior to the December 31, 2013 expiration of NPC’s current financing authority, NPC requests that its current authority be extended, as well as additional authority to refinance debt of $255 million. A hearing has been set for August 2013 to address whether NPC’s financing authority should be extended.

 Nevada Power Company

             NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIR and EEPR rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the table above.  Hearings are scheduled in mid-August 2013 with anticipated rates effective October 1, 2013.  The March 2013 application includes the following changes in revenue requirement (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR(1)		Oct. 2013	$	28.4	$	38.7	$	(10.3)
	TRED(1)		Oct. 2013		15.7		15.9		(0.2)
	EEPR Base(1)		Oct. 2013		45.9		32.6		13.3
	EEPR Amortization(1)		Oct. 2013		(29.9)		9.0		(38.9)
	EEIR Base		Oct. 2013		15.1		10.6		4.5
	EEIR Amortization		Oct. 2013		(6.7)		10.7		(17.4)
		Total Revenue Requirement		$	68.5	$	117.5	$	(49.0)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected.  As a result, such programs have no effect on Operating or Net Income.

24

   Sierra Pacific Power Company

 SPPC Electric General Rate Case

            In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations.  In this GRC, SPPC is requesting the following:

• Decrease in general rates by $9.4 million, approximately a 1.4% decrease; and

• ROE and ROR of 10.4% and 7.74%, respectively.

                        Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014. 

      SPPC Gas General Rate Case

                        In June 2013, SPPC filed a GRC for its gas operations.  In this GRC, SPPC is requesting the following:

• Increase in general rates by $10.2 million, approximately a 11.4% increase; and

• ROE and ROR of 10.35% and 7.72%, respectively.

                        Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.

       SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.  Hearings are scheduled in mid-August 2013 with anticipated rates effective October 1, 2013.  The March 2013 application includes the following changes in revenue requirement includes the following (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR (1)		Oct. 2013	$	42.3	$	44.4	$	(2.1)
	TRED (1)		Oct. 2013		7.4		6.3		1.1
	EEPR Base (1)		Oct. 2013		6.0		5.6		0.4
	EEPR Amortization (1)		Oct. 2013		(2.2)		1.8		(4.0)
	EEIR Base		Oct. 2013		5.6		4.7		0.9
	EEIR Amortization		Oct. 2013		1.1		1.9		(0.8)
		Total Revenue Requirement		$	60.2	$	64.7	$	(4.5)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected.  As a result, such programs have no effect on Operating or Net Income.

SPPC 2013 Nevada Gas DEAA and REPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.  The amounts requested in this filing result in an overall decrease in revenue requirement of $0.2 million, hearings are scheduled in mid-August 2013, with an anticipated effective date of October 2013.

FERC Matters

   NPC

NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003.  The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million.  In December 2012, FERC issued an order which suspended the proposed rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are currently subject to refund and final approval by the FERC.  However, at this time management is unable to determine the final revenue impact of the case.

25

   SPPC

      SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. On June 17, 2013, SPPC filed an unopposed settlement agreement resolving all issues with the FERC, which is pending before FERC for approval for rates effective June 1, 2013.    The rate changes under the terms of the settlement agreement are expected to result in an overall annual revenue increase of $1.5 million.

NVE, NPC and SPPC

2013 FERC Transmission Rate Case

In May 2013, NPC and SPPC filed an application with the FERC to reset transmission and ancillary service rates effective on the later of January 1, 2014, or the ON Line in-service date.  The rate changes reflect the addition of the ON Line in transmission revenue requirement.  Various interveners filed protests and NPC and SPPC filed a response to those protests on July 16, 2013.  FERC has not ruled on this application.  At this time, management is unable to determine the final revenue impact of the case.

FERC One Company Merger Request

In May 2013, NVE, NPC and SPPC filed an application with the FERCunder Section 203 of the Federal Power Act for Approval of Internal Reorganization.  In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and the surviving entity will be renamed NVEOC.  Under Section 203 of the Federal Power Act, the FERC may not authorize the Internal Reorganization unless it finds, among other things, that the transaction is “consistent with the public interest”. If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards. NPC and SPPC requested authorization by December 1, 2013 to enable the transaction to be effective on the latter of December 31, 2013, or the ON Line in-service date.  The application is currently pending before FERC for consideration.

FERC MidAmerican Merger Request

On July 12, 2013, an application was filed with the FERC under Section 203 of the Federal Power Act, to approve the MidAmerican Merger.  The MidAmerican Merger is discussed in more detail in Note 2, Merger Related Activities.   Under Section 203 of the Federal Power Act, the FERC may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “consistent with the public interest.”  If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards.  The application requests authorization of the proposed transaction by December 19, 2013; however, NVE is unable to determine the timing of a decision in the filing.

NOTE 5.LONG-TERM DEBT

NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands): 

						June 30,								December 31,
						2013								2012
Long-Term Debt:			Stated Rate		Maturity Date	Consolidated		NVE Holding Co.		NPC		SPPC		Consolidated		NVE Holding Co.		NPC		SPPC
Secured Debt
	General and Refunding Mortgage Securities
		NPC Series L	5.875	%	2015	$	250,000	$	-	$	250,000	$	-	$	250,000	$	-	$	250,000	$	-
		NPC Series M	5.950	%	2016		210,000		-		210,000		-		210,000		-		210,000		-
		NPC Series N	6.650	%	2036		370,000		-		370,000		-		370,000		-		370,000		-
		NPC Series O	6.500	%	2018		325,000		-		325,000		-		325,000		-		325,000		-
		NPC Series R	6.750	%	2037		350,000		-		350,000		-		350,000		-		350,000		-
		NPC Series S	6.500	%	2018		500,000		-		500,000		-		500,000		-		500,000		-
		NPC Series U	7.375	%	2014		125,000		-		125,000		-		125,000		-		125,000		-
		NPC Series V	7.125	%	2019		500,000		-		500,000		-		500,000		-		500,000		-
		NPC Series X	5.375	%	2040		250,000		-		250,000		-		250,000		-		250,000		-
		NPC Series Y	5.450	%	2041		250,000		-		250,000		-		250,000		-		250,000		-
		SPPC Series M	6.000	%	2016		450,000		-		-		450,000		450,000		-		-		450,000
		SPPC Series P	6.750	%	2037		251,742		-		-		251,742		251,742		-		-		251,742
		SPPC Series Q	5.450	%	2013		250,000		-		-		250,000		250,000		-		-		250,000
	Variable Rate Debt (Secured
	by General and Refunding
	Mortgage Securities)
		NPC IDRB Series 2000A			2020		98,100		-		98,100		-		98,100		-		98,100		-
		NPC PCRB Series 2006			2036		37,700		-		37,700		-		37,700		-		37,700		-
		NPC PCRB Series 2006A			2032		37,975		-		37,975		-		37,975		-		37,975		-
		SPPC PCRB Series 2006A			2031		58,200		-		-		58,200		58,200		-		-		58,200
		SPPC PCRB Series 2006B			2036		75,000		-		-		75,000		75,000		-		-		75,000
		SPPC PCRB Series 2006C			2036		81,475		-		-		81,475		81,475		-		-		81,475
Senior Notes
		NVE Senior Notes	6.250	%	2020		315,000		315,000		-		-		315,000		315,000		-		-
		NVE Term Loan	2.560	%	2014		195,000		195,000		-		-		195,000		195,000		-		-
Obligations under capital leases							42,154		-		40,233		1,921		44,258		-		42,908		1,350
Unamortized bond premium and discount, net							1,405		-		(9,329)		10,734		1,631		-		(9,827)		11,458
Current maturities							(480,018)		-		(229,743)		(250,275)		(356,283)		-		(106,048)		(250,235)
Total Long-Term Debt						$	4,543,733	$	510,000	$	3,104,936	$	928,797	$	4,669,798	$	510,000	$	3,230,808	$	928,990

26

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

Nevada Power Company

Notice of Redemption

On July 26, 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  NPC intends to redeem the aggregate principal amount outstanding of $98.1 million on August 21, 2013 at 100% of the principal amount plus accrued interest.  NPC intends to fund such redemption with the use of cash on hand.

NOTE 6. FAIR VALUE OF FINANCIAL INSTRUMENTS

The June 30, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments.  As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in the Rabbi Trust continue to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at June 30, 2013, is estimated to be $5.7 billion 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 was estimated to be $5.9 billion as of December 31, 2012.

The total fair value of NPC’s consolidated long-term debt at June 30, 2013, is estimated to be $3.9 billion 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 was estimated to be $4.1 billion at December 31, 2012.

The total fair value of SPPC’s consolidated long-term debt at June 30, 2013, is estimated to be $1.3 billion 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 was estimated to be $1.3 billion as of December 31, 2012. 

NOTE 7.RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location.  Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.   A summary of the components of net periodic pension and other postretirement costs, based on a December 31, 2012 measurement date, follows (dollars in thousands): 

NVE
	Pension Benefits					Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,132	$	4,406	$	660	$	595
Interest cost		9,303		10,228		1,677		1,905
Expected return on plan assets		(12,708)		(12,447)		(1,687)		(1,563)
Amortization of prior service cost		(720)		(724)		(952)		(987)
Amortization of net loss		4,797		3,473		890		731
Net periodic benefit cost	$	5,804	$	4,936	$	588	$	681
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	10,264	$	8,813	$	1,320	$	1,191
Interest cost		18,607		20,456		3,353		3,810
Expected return on plan assets		(25,416)		(24,894)		(3,373)		(3,126)
Amortization of prior service cost		(1,441)		(1,448)		(1,905)		(1,974)
Amortization of net loss		9,594		6,945		1,781		1,462
Net periodic benefit cost	$	11,608	$	9,872	$	1,176	$	1,363
The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.6% and 34.6%, respectively.

NPC
	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	2,761	$	2,358	$	389	$	350
Interest cost		4,453		4,881		556		602
Expected return on plan assets		(6,270)		(6,237)		(631)		(592)
Amortization of prior service cost		(453)		(456)		(23)		229
Amortization of net loss		2,117		1,363		289		221
Net periodic benefit cost	$	2,608	$	1,909	$	580	$	810
	Pension Benefits				Other Postretirement Benefits
		For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,522	$	4,715	$	778	$	700
Interest cost		8,905		9,762		1,111		1,205
Expected return on plan assets		(12,540)		(12,474)		(1,261)		(1,183)
Amortization of prior service cost		(905)		(912)		(46)		458
Amortization of net loss		4,234		2,726		578		441
Net periodic benefit cost	$	5,216	$	3,817	$	1,160	$	1,621
The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.7% and 36.6%, respectively.

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SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended June 30,				For the Three Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	1,926	$	1,695	$	251	$	227
Interest cost		4,558		5,043		1,104		1,283
Expected return on plan assets		(6,162)		(5,937)		(1,022)		(941)
Amortization of prior service cost		(277)		(277)		(933)		(1,220)
Amortization of net loss		2,501		2,026		592		504
Net periodic benefit cost	$	2,546	$	2,550	$	(8)	$	(147)
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	3,852	$	3,391	$	501	$	455
Interest cost		9,117		10,086		2,207		2,566
Expected return on plan assets		(12,324)		(11,875)		(2,043)		(1,882)
Amortization of prior service cost		(554)		(554)		(1,866)		(2,439)
Amortization of net loss		5,001		4,052		1,185		1,007
Net periodic benefit cost	$	5,092	$	5,100	$	(16)	$	(293)
The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 35.6% and 34.5%, respectively.

As discussed in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements in the 2012 Form 10-K, NVE offered a voluntary lump sum pension pay out to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation.  During the six months ended June 30, 2013, NVE paid $21.0 million in lump sum pension pay outs from the pension assets and does not expect any further material amounts due in 2013. 

During the six months ended June 30, 2013, NVE made no contributions to either of the plans.  At the present time, it is not anticipated that additional funding will be required for either plan in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding.  The amounts to be contributed in 2013 may change subject to market conditions.

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 $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs.  Management is under contract with a third party regarding the potential purchase of the property, subject to a 180 day due diligence period.

      Reid Gardner Generating Station

On October 4, 2011, NPC 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 NPC’s Reid Gardner Generating Station located near Moapa, Nevada.  NPC operates the facility and owns units 1-3.  Unit 4 of the facility is co-owned with the CDWR.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request.  At this time, NPC cannot predict the impact, if any, associated with this information request.

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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.  At this time, SPPC cannot predict the impact, if any, associated with this information request.

  NPC and SPPC

NVision and SB 123

NVision is a comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs.  NVision includes the following significant details:

• Accelerating the plan to retire 800 MW of coal plants, starting as soon as December 31, 2014;

• Replacement of such coal plants with the construction, acquisition or contracting for, 350 MWs of in state renewable capacity;

• Construction or acquisition and ownershipof gas-fired generating plants for 550 MWs;

• Implementation of programs to assist customers in reducing peak electric demand; and

• Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.

In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative and includesthe requirements as outlined in the bullets above.  The Utilities expect to file an IRP in 2014 to specifically address the plan details as outlined above.

Greenhouse Gas/Carbon Regulations

In conjunction with the release of President Obama’s Climate Action Plan on June 25, 2013, the President issued a memorandum directing the EPA to take several actions on carbon emissions standards for power plants.  As discussed above, NVision and the passage of SB 123, will yield substantial reductions in carbon as NVE and the Utilities retire their existing coal-fired generating facilities on an accelerated schedule. While the Utilities currently cannot predict the financial impact or final mandates by President Obama’s Climate Action Plan or the EPAs final rules, NVE and the Utilities remain committed to taking progressive steps over time to limit the carbon emissions from its generation fleet by retiring older fossil units and replacing them with new, lower emissions and/or zero emission sources.   

     Regional Haze Rules 

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO₂), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations.  In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at units 1-3 at the Reid Gardner Generating Station.  The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015.  In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station units at a later date.  In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station units 1-3, approving and rejecting certain components of Nevada’s SIP.For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice.  Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015.On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013,the EPA granted reconsideration of the compliance date for the BART retrofits for units 1, 2 and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015 to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action. The comment period for this action closed on May 30, 2013 and the EPA is expected to finalize its decision by the end of the summer.  

NVE continues to work toward finalizing the retrofit designs for the affected BART units.  NVE has received approval from the PUCN to retire Tracy Generating Station units 1 and 2, and install retrofit controls on Tracy Generating Station unit 3 and Ft. Churchill Generating Station units 1 and 2.  As previously disclosed, NVE and the Utilities intend to also file with the PUCN their IRP detailing how they will address the phased retirement of coal fired assets as required under SB 123.  While the BART requirements specify the installation of SNCR’s on Reid Gardner Generating Station units 1, 2 and 3, the passage of SB 123 could result in the early retirement of those units prior to the required BART installation deadline, pending the final approval of the PUCN.  Therefore, in NVE and the Utilities’ IRP filing planned for 2014, NVE and the Utilities would need to obtain either the PUCN approval to retire those units as soon as the end of 2014 or seek approval for the BART retrofit installation with an alternate retirement date.  Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, including Reid Gardner units 1, 2 and 3, but excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units.  NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal.  In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule.  NVE has intervened in that lawsuit.  In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station.  NVE has intervened in this lawsuit.  At this time management is unable to determine the likelihood of success by petitioners in these litigation matters.  An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. 

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The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPAannounced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline forreducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impacton the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019.  Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations.  It is believed that the EPA BART proposal will require an investment of up to $1.1 billion inadditional emission controls at the plant of which NPC’s ownership share is 11.3%.

The comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested a 90-day extension, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners.  In March 2013, the EPA granted a 90-day extension to August 5, 2013.  On June 26, 2013, the EPA provided a second extension of the public comment period for the proposed rulemaking on Navajo Generating Station based on a request from Salt River, on behalf of the Navajo Nation, the Gila River Indian Community, the Central Arizona Water Conservation District, the Environmental Defense Fund and the U.S. Department of the Interior.The EPA is extending the comment period an additional 60-days and the public comment period will now close on October 4, 2013.Prior to the close of the public comment period, the EPA has announced it will hold a hearing at one location each on the Navajo Reservation and the Hopi Reservations.

Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear,and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized.  NVE cannot predictat this timethe ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take at this time.

      Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Registera final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units.  The rule, referred to as the MATS rule, requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the Maximum Achievable Control Technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia.  The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards.  Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO₂ and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, unit 1 to achieve compliance with the MATS standards.  At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC.  Note that the actual cost will be dependent upon final engineering design.

The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order to allow for additional testing of various mercury control strategies.  Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo Generating Station units, a cost estimate is unable to be determined at this time.

Currently, all four of the units at the Reid Gardner Generating Station, as well as unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend.  However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

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.  In addition, NVE and the Utilities may also be subject to future state or federal regulations.  Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites.  This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties.  The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation.  Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility.  If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties.  In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs.  These types of sites/situations are generally managed in the normal course of business operations.

                        In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station units 1, 2 and 3 and as co-owners and operating agent of unit 4.  Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs.  However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

                        NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

Litigation Contingencies

   NVE

Litigation Related to the MidAmerican Merger

Following the announcement of the proposed acquisition of NVE by MEHC through its subsidiary Silver Merger Sub, Inc. on May 29, 2013, several complaints were filed by alleged NVE shareholders in the Eighth Judicial District Court in Clark County, Nevada, challenging the MidAmerican Merger.

On June 6, 2013, a complaint was filed on behalf of a putative class of NVE public shareholders, naming NVE, its BOD, and Silver Merger Sub, Inc., as defendants. This complaint was amended on July 16, 2013.  The amended complaint generally alleges that the individual defendants breached their fiduciary duties in connection with the proposed MidAmerican Merger, including by approving the transaction on allegedly unfair terms, at an allegedly unfair price and pursuant to an allegedly inadequate process; allegedly acting with conflicts and in their own personal interests rather than those of shareholders; and making inadequate disclosures in connection with requested shareholder approval of the proposed MidAmerican Merger.  The amended complaint also alleges that Silver Merger Sub. Inc., NVE and MEHC aided and abetted the individual defendants in breaching their fiduciary duties. 

Three additional complaints were filed on June 7, 2013, June 10, 2013 and July 12, 2013, respectively.  These complaints contain claims and allegations similar to the amended July 16, 2013 complaint and seek similar relief on behalf of the same putative class.

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The outcome of these lawsuits is uncertain.  An adverse judgment could have a material adverse effect on the operations of NVE, including the possibility of delaying or permanently enjoining the MidAmerican Merger.  NVE and its BOD intend to vigorously defend the lawsuits. 

NPC 

      Peabody Western Coal Company – Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and 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.

In June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”).  NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process.  The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit.  In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement amongthe Navajo Nation, Peabody, Salt River and SCE.  At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station. 

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station.  NPC has reached a tentative settlement with SCE on this matter.  The terms of the settlement will not be material to NPC.

     SPPC

        Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million.  One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume.  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.  The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers.  The insurers contested the extent and amount of insurance coverage.  Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost.  In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

   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.

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which theUtilities expect to get regulatory recovery. For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of June  30, 2013, capitalized construction costs associated with GBT’s 75% interest of $336.1 million and $20.7million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

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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. 

			Three Months Ended June 30,				Six Months Ended June 30,
			2013		2012		2013		2012
Basic EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator
		Weighted average number of common shares outstanding		235,489,559		235,999,750		235,342,448		235,999,750
	Per Share Amounts
		Net Income per share - basic	$	0.27	$	0.29	$	0.36	$	0.35
Diluted EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator(1)
		Weighted average number of shares outstanding before dilution		235,489,559		235,999,750		235,342,448		235,999,750
		Stock options		58,916		38,237		38,842		36,760
		Non-Employee Director stock plan		185,335		160,257		182,653		156,972
		Employee stock purchase plan		2,719		2,725		6,672		6,807
		Restricted Shares		472,000		518,750		525,500		508,250
		Performance Shares		1,192,871		1,183,557		1,108,390		1,006,531
	Diluted Weighted Average Number of Shares			237,401,400		237,903,276		237,204,505		237,715,070
	Per Share Amounts
		Net income per share - diluted	$	0.27	$	0.29	$	0.36	$	0.34
	(1)	The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending June 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 330,322 shares, would be included for the three and six months ended June 30, 2012, respectively.

NOTE 10.COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date		Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$	0.19	March 20, 2013	March 5, 2013
May 8, 2013	$	0.19	June 19, 2013	June 4, 2013
August 1, 2013	$	0.19	September 18, 2013	September 3, 2013

On August 1, 2013, NPC and SPPC declared dividends payable to NVE of $25.0 million and $20.0 million, respectively. For the six months ended June 30, 2013, NPC and SPPC paid dividends to NVE of $80.0 million and $20.0 million, respectively.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program.  All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award.  Treasury stock is accounted for using the cost method. During the six months ended June 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million.  During the six months ended June 30, 2013, NVE re-issued 792,946 treasury shares to satisfy employee benefit plans.In May 2013, NVE ceased the repurchase of common stock as a result of the proposed MidAmerican Merger. 

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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:

Risks Related to the Pending MidAmerican Merger

• whether NVE or MEHC will be able to satisfy the closing conditions of the MidAmerican Merger Agreement, including the approval of the MidAmerican Merger by NVE shareholders and the receipt of certain regulatory approvals on the terms and schedules contemplated by the parties, including, among other regulatory approvals, approvals from the PUCN and the FERC;

• whether an event, effect or change will occur that gives rise to a termination of the MidAmerican Merger;

• whether NVE will experience unanticipated difficulties and/or incur unanticipated expenditures relating to the MidAmerican Merger, and whether the MidAmerican Merger will disrupt current plans and operations and create difficulties in employee retention;

• whether legal proceedings against NVE and others related to the MidAmerican Merger will be successful; and

• the impact of delay or failure to complete the MidAmerican Merger on NVE’s common stock price.

Operational Risks

• economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;

• changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

• construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;

• security breaches of our information technology or supervisory control and data systems, or the systems of others  upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information; 

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

• employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, and the ability to adjust the labor cost structure to changes in growth within our service territories;

• whether the Utilities’ NV Energize systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;

• changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;

• explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

• the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;

• changes in the business of the Utilities’ major customers engaged in mining or gaming, including availability and cost of capital or power demands, which may result in changes in the demand for the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;

• 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; and

• unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.

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Regulatory/Legislative Risks

• unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;

• the effect of existing or future Nevada or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;

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

• changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.

Environmental Risks

• changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.

Liquidity and Capital Resources Risks

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

• wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

• whether provisions of the Dodd-Frank Act or rules made under the act governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the cost, or limit the availability or usefulness, to the Utilities of financial transactions and techniques important in managing risks the Utilities face in the commodity, power and financial markets; 

• the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, 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;

• whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s 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 contained in NVE's and the Utilities' agreements;

• 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; and

• 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 and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.

Other factors and assumptions not identified above may also have been involved in deriving 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.

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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 that are specific to the applicable agreement.  These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

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

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

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

• were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements 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.

NOTE REGARDING STATISTICAL DATA

The statistical data used throughout this 10-Q, other than data relating specifically to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.   NVE and the Utilities did not commission any of these publications or reports.  These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information.  While NVE and the Utilities believe that each of these studies and publications is reliable, NVE and the Utilities have not independently verified such data and make no representation as to the accuracy of such information.

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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 discussion of the following:

• Critical Accounting Policies and Estimates:

• Recent Pronouncements

• 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 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.

The Utilities are regulated by the PUCN 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, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term energy supply 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 through rates are essential to the operating and financial performance of the Utilities. 

MidAmerican Merger

In May 2013, NVE entered into the MidAmerican Merger.  The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation in the MidAmerican Merger.  Once merged, NVE will become an indirect wholly-owned subsidiary of MEHC, which in turn is a wholly-owned subsidiary of Berkshire Hathaway, Inc.  Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest.  The MidAmerican Merger Agreementis subject to various conditions and is discussed in more detail in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements.  In order to meet the targeted closing time frame in the first quarter of 2014, NVE will work diligently to satisfy the conditions as outlined in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements, as well as transitional requirements. 

Overview of Major Factors Affecting Results of Operations

NVE recognized net income of $63.2 million for the three months ended June 30, 2013, compared to $69.4 million for the same period in 2012.  The decrease in net income is primarily due to the following pre-tax items:

• MidAmerican Merger related costs of $13.6 million as discussed in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements;

• An increase in other operating expense primarily due to an increase in rate case related fees, consulting fees and lower allocations to capital projects; see the Utilities’ respective Results of Operations for further discussion;

• An increase in depreciation expense primarily due to the completion of various projects; and

• A decrease in other income primarily due to income recognized in 2012 for a construction contract settlement for the Harry Allen Generating Station.

These decreases were partially offset by the following pre-tax items:

• An increase in gross margin of $9.2 million; see the Utilities’ respective Results of Operations for further discussion of gross margin;

• A decrease in interest expense on regulatory items of $2.0 million primarily due to lower under collected deferred energy and regulatory balances; and

• A decrease in interest expense primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012.

NVE recognized net income of $84.7 million for the six months ended June 30, 2013, compared to $81.6 million for the same period in 2012.  The increase in net income is primarily due to the following pre-tax items:

• An increase in gross margin of $18.5 million; see the Utilities’ respective Results of Operations for further discussion of gross margin;

• A decrease inmaintenance expense primarily due to a decrease in outages of approximately $7.9 million;

• A decrease in interest expense of $5.6 million primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012 and an increase in AFUDC-debt; and

• A decrease in interest expense on regulatory items of $3.3 million primarily due to lower under collected deferred energy and regulatory balances.

These increases were partially offset by the following pre-tax items:

• MidAmerican Merger related costs of $13.6 million as discussed in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements;

• An increase in other operating expense primarily due to an increase in rate case related fees, consulting fees and lower allocations to capital projects; see the Utilities’ respective Results of Operations for further discussion;

• An increase in depreciation expense primarily due to the completion of various projects; and

• A decrease in other income primarily due to income recognized in 2012 for a construction contract settlement for the Harry Allen Generating Station.

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NVE Transformation

Beginning in 2006, NVE committed to an energy strategy to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as, expanding our transmission capability in an effort to reduce our reliance on purchased power.  The implementation of this strategy required significant amounts of liquidity and capital.  To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs.  At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costsincurred and the importance of a reasonable and timely return on such investments for our shareholders. 

The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn their allowable return on their investments while meeting a higher percentage of their load through owned generation.  Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continue to improve.  Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable.  As a result, NVE expects to generate free cash flow in 2013, which will continue to provide NVE the ability to maintain its dividend. 

Key Initiatives

The economy in Nevada continues to recover slowly.  While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment.  However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further strengthen our capital structure and to consider new investment opportunities.  In addition, NVE management remains focused on the execution of the MidAmerican Merger. These initiatives should enable us to contain operating and maintenance costs while effectively managing our regulatory environment and continuing to promote and improve a safe and reliable work environment.  These key initiatives are discussed below.

Continuous Improvement ofSafety 

The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into its business operations and culture.  These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions.  Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company. 

Construction of ON Line

ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in late 2013, will connect NVE’s southern and northern service territories.  Pending certain state and federal regulatory approvals, ON Line will provide:

• Ability to dispatch energy jointly throughout the state;

• Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada which will enhance NVE’s ability to meet its Portfolio Standard; and

• Ability to optimize its generating and transmission facilities to benefit its customers.

One Company Merger

In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:

• Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility NVEOC;

• Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and

• Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”Hearings are expected to begin in February 2014. 

Empower Customers through Focused Service and Efficiency Programs

NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.  The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options.  Since April 30, 2013, the project was deemed to be substantially complete.  SPPC has included its proportionate share in its 2013 GRC and NPC’s proportionate share will be included in a future rate case. 

The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests.  The system also enables NVE to launch new customer programs.  Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway.  New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information.  An enhanced air conditioning demand response program was launched in the fourth quarter.   It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability.  Similar programs for commercial customers are under development.

Managing Generation Portfolio within Environmental Compliance

As discussed in more detail in Note 8, Commitments and Contingencies of the Condensed Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules.  The implementation costs of the Regional Haze Rules are significant.  Therefore, NVE must balance the cost of implementing the retrofits associated with the Regional Haze Rule with the effect current and future load requirements, retirements of generating stations, including the effects of NVision discussed below, and plant outages will have on its ability to serve its customers reliably.  In that end, the PUCN has accepted the Utilities’ resource plan to install necessary controls on the Tracy Generating Station unit 3 and Fort Churchill Generating Station units 1 and  2 to comply with Regional  Haze.  Tracy Generating Station units 1 and 2 will be retired on or before the regional haze compliance date.  Reid Gardner Generating Station units 1, 2 and 3 are also affected by the regional haze compliance date, but no decision has been made for these units at this time as NVE considers the impacts of NVision on these units.

 Investment Opportunities

NVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy.  In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.

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NVision and SB 123

As discussed further in Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, NVision isNVE’s comprehensive plan for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs.

In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative.  The Utilities expect to file an IRP in 2014 to specifically address the plan details as outlined above.

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 $12.6 millionand $12.6 million of long-term debt interest costs for the six months ended June 30, 2013 and 2012, respectively. 

For the period ended June 30, 2013, NPC and SPPC paid $80.0 million and $20.0 million, respectively, in dividends to NVE.  On August 1, 2013, NPC and SPPC declared dividends payable to NVE of $25.0 million and $20.0 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

NVE’s cash flows decreased during the six months ended June 30, 2013, compared to the same period in 2012, due to an increase in cash used by financing activities, offset partially by an increase in cash from operating activities and a decrease in cash used by investing activities.

Cash From Operating Activities

NVE’s net cash flows from operating activities were $228.1 million and $292.7 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash from operating activities was primarily due to:

• Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of $218.8 million, offset by reduced refunds to customers of $54.3 million;

• Reduced EEPR collections of $28.2 million; and

• Timing of payments for outages at Reid Gardner and Lenzie Generating Stations of $23.2 million.

The decrease in cash from operating activities was partially offset by:

• Reduced coal purchases of $25.1 million;

• Timing of payments for energy costs of $19.7 million;

• Reduced expenditures on renewable programs of $22 million; and

• Receipt of approximately $9 million in insurance proceeds related to a previous claim.

Cash Used By Investing Activities

NVE’s net cash used by investing activities were $168.6 million and $217.4 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash used by investing activities was primarily due to:

• Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $57.5 million; and

• Reduced capital expenditure for the NV Energize project of $70 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $17.6 million.

Cash Used By Financing Activities

NVE’s net cash flows used by financing activities were $96.8 million and $98.4 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash used by financing activities was primarily due to:

• Reduction of cash used to retire debt of $155 million.

The decrease in cash used by financing activities was partially offset by:

• Reduction of draws from the NPC revolving credit facility of $135 million;

• Repurchase of common stock, to satisfy future equity compensation awards of $6.3 million; and

• Increased dividends to shareholders of $18.7 million.

NVE paid common stock dividends of $89.5 million and $70.8 million during the periods ending June 30, 2013 and 2012, respectively.

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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.  Another significant use of cash is the refunding of previously over-collected BTER amounts from customers.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions.  Available liquidity as ofJune 30, 2013 was as follows (in millions):

Available Liquidity as of June 30, 2013 (in millions)
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	24.7	$	141.7	$	92.0
	Balance available on Revolving Credit Facilities(1)			N/A		500.0		243.7
				24.7		641.7		335.7
(1)		As of August 1, 2013, NPC and SPPC had approximately $500 million and $243.7 million available under their revolving credit facilities, which includes reductions in availability for letters of credit.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  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 has no debt maturities in 2013.However, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020 prior to ON Line’s commercial operation date expected by December 31, 2013.  On July 26, 2013, NPC issued a notice to redeem the $98.1 million on August 21, 2013; see Note 5, Long-Term Debt, of the Condensed Notes to Financial Statements.  In addition, NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature in September 2013.  To meet these long-term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long-term debt.  The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below).  NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013.  However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NVE and the Utilities have transitionedto slower growth, the amount of capital expenditures has declined.  NVE’s and the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources.  As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities’ revolving credit facilities.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to maintain our dividend payout and for potential investment opportunities.

However, if energy costs rise at a rapid rate, or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NVE and the Utilities may be required to delay capital expenditures or refinance debt.  Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs.  Currently, the Utilities are not operating under a PUCN approved hedging plan.  Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner. 

As of August 1, 2013, NVE has approximately $12.1 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  For the six months ended June 30, 2013, NPC and SPPC paid dividends to NVE of approximately $80.0 million and $20.0 million, respectively.On August 1, 2013, NPC and SPPC declared dividends payable to NVE of $25.0 million and $20.0 million, respectively.

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, environmental compliance, improvement and maintenance of facilities.  As discussed, in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s termination payment of Reid Gardner Generating Station unit 4 from CDWR, which is expected to be completed mid-2013 for approximately $47.1 million, subject to final approval by the FERC. 

During the six months ended June 30, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K except for in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN.  The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period.  However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million. 

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, 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 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed 0.70 to 1.00.  Under these covenant restrictions, as of June 30, 2013, NVE (consolidated) would be allowed to incur up to $3.3 billionof additional indebtedness.  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.  NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.

   Effect of Holding Company Structure

As of June 30, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due 2014; and$315 million of unsecured 6.25% Senior Notes due 2020.

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.

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As of June 30, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $5.0 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries.  Although NVE and the Utilities are parties to agreements that 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 may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of June 30, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.

 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 being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such 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

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt.On May 22, 2013, Moody’s upgraded NVE’s, NPC’s and SPPC’s ratings.  On May 30, 2013, Fitch and Standard & Poor’s upgraded NPC’s and SPPC’s rating outlook from Stable to Positive.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P.  As of June 30, 2013, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NVE		Sr. Unsecured Debt	BB+	Baa3*	BB+
NPC		Sr. Secured Debt	BBB+*	A3*	BBB+*
SPPC		Sr. Secured Debt	BBB+*	A3*	BBB+*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

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.  Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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, which includes a credit rating downgrade of 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 June 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $116.3 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.

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 mean 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 a 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 June 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings both are downgraded to below investment grade.

Financial Gas Hedges

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The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K, NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net 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 exceed 50% of the total commitments then in effect under the credit facilities.  Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities.  If deemed prudent, the Utilities may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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 an 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 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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities.  As a result, NVE, NPC and SPPC will be required to offer for purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers.The average interest rate under these financing agreements is approximately 6.25%, 6.42% and 6.05% for NVE, NPC and SPPC, respectively.  To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt.Furthermore, NVE and the Utilities are required to obtain consents from lenders under the terms of Utilities’ revolving credit facilities and NVE’s term loan before consummating the MidAmerican Merger.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $58.7million during the three months ended June 30, 2013, compared to $62.3 million for the same period in 2012. During the six months ended June 30, 2013, NPC recognized net income of approximately $64.1 million, compared to $61.0 million for the same period in 2012.

For the period ended June 30, 2013, NPC paid $80.0 million in dividends to NVE.  On August 1, 2013, NPC declared a dividend of $25.0 million to NVE.

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 and energy efficiency program costs, provides a measure of income available to support the other operating expenses of NPC.  For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

	The components of gross margin were (dollars in thousands):
		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013			2012		Variance	% Change
Operating Revenues:		$	537,124	$	553,143	$	(16,019)	(2.9)%	$	908,987	$	948,831	$	(39,844)	(4.2)%
Energy Costs:
	Fuel for power generation		144,246		81,258		62,988	77.5 %		249,777		161,807		87,970	54.4 %
	Purchased power		129,396		135,276		(5,880)	(4.3)%		210,804		216,807		(6,003)	(2.8)%
	Deferred energy		(63,748)		5,053		(68,801)	(1361.6)%		(109,103)		7,224		(116,327)	(1610.3)%
Energy efficiency program costs			10,842		21,200		(10,358)	(48.9)%		18,809		36,974		(18,165)	(49.1)%
	Total Costs	$	220,736	$	242,787	$	(22,051)	(9.1)%	$	370,287	$	422,812	$	(52,525)	(12.4)%
Gross Margin		$	316,388	$	310,356	$	6,032	1.9 %	$	538,700	$	526,019	$	12,681	2.4 %

Gross margin increased for the three months ended June 30, 2013, compared to the same period in 2012. The increase is primarily due to an increase in customer usage, excluding the effects of weather, customer growth and an increase in EEIR revenue and rental income.  The increases were partially offset by a decrease in usage due to weather. 

Gross margin increased for the six months ended June 30, 2013 compared to the same period in 2012.  Gross margin increased primarily due to customer growth, an increase in BTGR revenues, an increase in usage primarily due to weather and to a lesser extent an increase in EEIR revenue.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDswithin NPC’s service territory:

		Three Months Ended June 30,					Six Months Ended June 30,
		2013	2012	Variance	% Change		2013	2012	Variance	% Change
NPC
	Heating	34	62	(28)	(45.2)	%	1,084	986	98	9.9	%
	Cooling	1,408	1,417	(9)	(0.6)	%	1,494	1,458	36	2.5	%

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

Operating Revenue
			Three Months Ended June 30,							Six Months Ended June 30,
			2013		2012		Variance		% Change	2013		2012		Variance		% Change
Operating Revenues:
	Residential		$	279,057	$	284,930	$	(5,873)	(2.1) %	$	470,952	$	479,419	$	(8,467)	(1.8) %
	Commercial			105,909		109,057		(3,148)	(2.9) %		185,469		196,792		(11,323)	(5.8) %
	Industrial			137,608		145,810		(8,202)	(5.6) %		226,086		245,724		(19,638)	(8.0) %
		Retail  revenues		522,574		539,797		(17,223)	(3.2) %		882,507		921,935		(39,428)	(4.3) %
	Other			14,550		13,346		1,204	9.0  %		26,480		26,896		(416)	(1.5) %
		Total Operating Revenues	$	537,124	$	553,143	$	(16,019)	(2.9) %	$	908,987	$	948,831	$	(39,844)	(4.2) %
Retail sales in thousands of MWhs
		Residential		2,354		2,331		23	1.0  %		3,965		3,867		98	2.5  %
		Commercial		1,178		1,149		29	2.5  %		2,095		2,107		(12)	(0.6) %
		Industrial		2,043		2,040		3	0.1  %		3,677		3,691		(14)	(0.4) %
Retail sales in thousands of MWhs				5,575		5,520		55	1.0  %		9,737		9,665		72	0.7  %
Average retail revenue per MWh			$	93.74	$	97.79	$	(4.05)	(4.1) %	$	90.63	$	95.39	$	(4.76)	(5.0) %

NPC’s retail revenues decreased for the three months ended June 30, 2013, as compared to the same period in 2012 due to $11.8 million in net rate decreases as a result of NPC’s various BTER and DEAA quarterly updates partially offset by an increase in BTGR revenues (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K), and $10.3 million from decreases in EEPR rates effective January 1, 2013. These decreases were offset by an increase of $3.0 million from customer growth.

For the three months ended June 30, 2013, the average number of retail customers increased by 1.2%, consisting of an increase in residential and commercial customers of 1.1% and 2.1%, respectively, and a decrease in industrial customers of 0.2%, compared to the same period in the prior year.

NPC’s retail revenues decreased for the six months ended June 30, 2013, compared to the same period in 2012.  Similar to the three month period discussed above, the decrease was due to $33.7 million in net rate decreases as a result of NPC’s various BTER and DEAA quarterly updates partially offset by an increase in BTGR revenues (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K), and $18.0 million from decreases in EEPR rates effective January 1, 2013. These decreases were offset by an increase of $5.1 million from increased usage, caused by an unusually cold January and an unusually hot June. The decreases were further offset by an increase of $3.3 million from customer growth.

For the six months ended June 30, 2013, the average number of retail customers increased by 0.9%, consisting of an increase in residential, commercial and industrial customers of 0.8%, 1.6% and 0.3%, respectively, compared to 2012. 

Electric Operating Revenues – Other for the three months and six months ended June 30, 2013, compared to the same periods in 2012, did not change materially.

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

• mandated power purchases; and

• volatility of commodity prices

		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013		2012			Variance	% Change
Energy Costs
	Fuel for power generation	$	144,246	$	81,258	$	62,988	77.5  %	$	249,777	$	161,807	$	87,970	54.4 %
	Purchased power		129,396		135,276		(5,880)	(4.3) %		210,804		216,807		(6,003)	(2.8)%
Energy Costs		$	273,642	$	216,534	$	57,108	26.4  %	$	460,581	$	378,614	$	81,967	21.6 %
MWhs
	MWhs Generated (in thousands)		4,393		3,871		522	13.5  %		8,068		7,158		910	12.7 %
	Purchased Power (in thousands)		1,505		1,997		(492)	(24.6) %		2,148		3,023		(875)	(28.9)%
Total MWhs			5,898		5,868		30	0.5  %		10,216		10,181		35	0.3 %
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	32.84	$	20.99	$	11.84	56.4  %	$	30.96	$	22.61	$	8.35	37.0 %
	Average cost per MWh of Purchased Power	$	85.98	$	67.74	$	18.24	26.9  %	$	98.14	$	71.72	$	26.42	36.8 %
	Average total cost per MWh	$	46.40	$	36.90	$	9.50	25.7  %	$	45.08	$	37.19	$	7.89	21.2 %

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Energy Costs and the average total cost per MWh increased for the three and six months ended June 30, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power.

• Fuel for generation costs increased for the three months ended June 30, 2013, compared to the same period in 2012.  Approximately $48.4 million of the increase was attributable to anincrease in natural gas prices, plus an increase of $14.6 million as a result of an increase in volume. Fuel for generation costs increased for the six months ended June 30, 2013, compared to the same periods in 2012.  Similar to the discussion above of the three month period, approximately $61.5 million of the increase was attributable to an increase in natural gas prices,plus an increase of $26.4 million as a result of an increase in volume.

• Purchased power costs decreased for the three months ended June 30, 2013, compared to the same period in 2012.  The decrease in purchased power costs for the three month period is primarily due to a $28.8 million decrease in volume of non-renewable purchases and a $13.3 million decrease in renewable purchases. The decrease in cost was partially offset by anincrease in the cost of non-renewable power purchases of approximately $23.4 million primarily driven by higher natural gas prices and an increase in the cost of renewable power purchases of $12.8 million. Purchased power costs decreased for the six months ended June 30, 2013, compared to the same period in 2012. The decrease is primarily due to an approximately $61.5 million decrease in volume of non-renewable power purchases and a $25.7 million decrease in the volume of renewable purchases. The decrease was offset by an increase in the cost of non-renewable purchases of approximately $52.9 million primarily due to higher gas prices and an increase in renewable purchases of $28.3 million.

Deferred Energy
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013		2012			Variance	% Change
Deferred energy	$	(63,748)	$	5,053	$	(68,801)	(1,361.6) %	$	(109,103)	$	7,224	$	(116,327)	(1,610.3)%

Deferred Energy for the three months ended June 30, 2013 and 2012 include amortization of deferred energy of $(23.6) million and $(42.9) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy balance areunder-collections of amounts recoverable in rates of $(40.2) million in 2013 and over-collections of $48.0 million in 2012. 

Amounts for the six months ended June 30, 2013 and 2012 include amortization of deferred energy of $(50.9) million and $(78.1) million, respectivelywhich primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy balance areunder-collections of amounts recoverable in rates of $(58.2) million in 2013, and over-collections of $85.4 million in 2012. 

Deferred energy 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 also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013		2012			Variance	% Change
Energy efficiency program costs	$	10,842	$	21,200	$	(10,358)	(48.9) %	$	18,809	$	36,974	$	(18,165)	(49.1) %
Merger related costs	$	8,867	$	-	$	8,867	N/A %	$	8,867	$	-	$	8,867	N/A %
Other operating expenses	$	70,100	$	68,650	$	1,450	2.1  %	$	137,492	$	135,112	$	2,380	1.8  %
Maintenance	$	15,889	$	16,988	$	(1,099)	(6.5) %	$	33,964	$	40,061	$	(6,097)	(15.2) %
Depreciation and amortization	$	70,405	$	69,131	$	1,274	1.8  %	$	139,066	$	134,121	$	4,945	3.7  %

For the three and six months ended June 30, 2013 energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings.

As discussed further in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement.  As a result of the MidAmerican Merger, NPC incurred additional merger related fees and stock compensation costs for the three and six months ended June 30, 2013.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger.  NPC expects to incur additional merger related fees upon shareholder approval of the MidAmerican Merger, as well as, upon consummation of the MidAmerican Merger.

Other operating expense increased for the three months ended June 30, 2013, compared to the same period in 2012, primarily due to a $1.5 million reduction in capitalized costs as a result of a decrease in construction activity, a $1.5 million increase in outside consulting fees, a $1.3 million increase in rate case related expenses, and a $1.1 million increase in reserves for bad debt.  The increase was partially offset by a $3.5 million decrease in stock compensation costs as a result of additional vesting of stock awards in 2012, and a $1.2 million decrease in injury and damage related expenses.

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Other operating expense increased for the six months ended June 30, 2013, compared to the same period in 2012, primarily due to a $2.3 million reduction in capitalized costs as a result of a decrease in construction activity, a $2.0 million increase in outside consulting fees, a $1.4 million increase in reserves for bad debt, and a $1.3 million increase in rate case related expenses.  The increase was partially offset by a $1.3 million decrease in injury and damage related expenses, and a $1.1 million decrease in pension and benefit costs.

Maintenance expense decreased for the threemonths ended June 30, 2013, compared to the same period in 2012, primarily due to $4.1 million of majorplanned maintenance outages in 2012 at the Lenzie, Silverhawk and Reid Gardner Generating Stations, offset by $3.5 million of planned maintenance outages in 2013 at the Higgins and Clark Generating Stations.   

Maintenance expense decreased for the six months ended June 30, 2013, compared to the same period in 2012, primarily due to $8.4 million of major planned maintenance outages in 2012 at the Silverhawk, Lenzie and Reid Gardner Generating Stations, offset by $2.6 million of planned maintenance outages in 2013 at the Higginsand Clark Generating Stations.   

Depreciation and amortization increased for the three and six months ended June 30, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.

Interest Expense
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013			2012		Variance	% Change
Interest expense
(net of AFUDC-debt: $1,406, $1,314, $3,243 and $2,493)	$	51,643	$	52,602	$	(959)	(1.8) %	$	102,902	$	107,007	$	(4,105)	(3.8) %

Interest expense decreased for the three months ended June 30, 2013, compared to the same period in 2012 due to a $0.5 million decrease in interest costs related to the credit facility in 2013, and a $0.4 million decrease in interest costs primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Interest expense decreased for the six months ended June 30, 2013, compared to the same period in 2012 due to a $2.5 million decrease in interest costs primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012, an increase in AFUDC-debt of $0.7 million and a $0.5 million decrease in interest costs related to the credit facility in 2013. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Other Income (Expense)
		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013		2012			Variance	% Change
Interest income (expense) on
	regulatory items	$	(181)	$	(1,849)	$	1,668	(90.2) %	$	(983)	$	(3,865)	$	2,882	(74.6) %
AFUDC-equity		$	1,826	$	1,577	$	249	15.8  %	$	4,192	$	2,990	$	1,202	40.2  %
Other income		$	978	$	5,392	$	(4,414)	(81.9) %	$	3,382	$	7,101	$	(3,719)	(52.4) %
Other expense		$	(1,833)	$	(2,993)	$	1,160	(38.8) %	$	(4,234)	$	(4,339)	$	105	(2.4) %

Interest expense on regulatory items decreased for the three months ended June 30, 2013, compared to the same period in 2012, due to a $2.6 million decrease in interest on deferred energy as a result of lower over-collected balances in 2013, offset by $1.3 million net decrease of interest income due to lower regulatory asset balances.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K. 

Interest expense on regulatory items decreased for the six months ended June 30, 2013, compared to the same period in 2012, due to a $4.2 million decrease in interest on deferred energy as a result of lower over-collected balances in 2013, and a decrease of $0.7 million in estimated interest expense accrued on the deferred gain on NPC’s wireless towers sold in 2011 pending final accounting approval by the PUCN in 2012, offset by $2.6 million net decrease of interest income due to lower regulatory asset balances.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K.

AFUDC-equity increased for the three and six months ended June 30, 2013, compared to the same periods in 2012, primarily due to various construction projects. 

Other income decreased for the three and six months ended June 30, 2013, compared to the same periods in 2012, due to a $4.9 million Harry Allen Generating Station construction project settlement recorded in 2012, offset slightly by several items, none of which were individually material.

Other expense decreased for the three and six months ended June 30, 2013, compared to the same periods in 2012, due to several items, none of which were individually material.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the six months ended June 30, 2013, compared to the same period in 2012, due to a decrease in cash from operating activities and an increase in cash used by investing and financing activities.

Cash From Operating Activities

NPC’s net cash flows from operating activities were $128.6 million and $226.3 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash from operating activities was primarily due to:

• Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of$144.7 million,offset by reduced refunds to customers of $27.2 million;

• Reduced EEPR collections of $24.4 million; and

• Timing of payments for outages at Reid Gardner and Lenzie Generating Stations of $23.2 million.

The decrease in cash from operating activities was partially offset by:

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• Reduced expenditures on renewable programs of $5.6 million;

• Reduced coal purchases of $3.5 million; and

• Timing of payments for energy costs of $8.7 million.

Cash Used By Investing Activities

NPC’s net cash used by investing activities were $105.8 million and $138.8 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash used by investing activities was primarily due to:

• Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations, increasing cash $57.5 million; and

• Reduced capital expenditure for the NV Energize project of $8 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $8.1 million.

Cash Used By Financing Activities

NPC’s net cash flows used by financing activities were $82.3 million and $104.4 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash used by financing activities was primarily due to:

• Reduced cash used to retire debt of $155 million.

The decrease in cash used by financing activities was partially offset by:

• Reduced draws from the NPC revolving credit facility of $135 million.

NPC paid dividends of $80 million and $79 million to NVE during the period ending June 30, 2013 and 2012, respectively.

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.  Another significant use of cash is the refunding of previously over-collected amounts from customers.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of June 30, 2013 was as follows (in millions):

Available Liquidity as of June 30, 2013 (in millions)
			NPC
Cash and Cash Equivalents			$	141.7
	Balance available on Revolving Credit Facility(1)			500.0
			$	641.7
(1)		As of August 1, 2013, NPC had approximately $500 million available under its revolving credit facility.

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

NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013.  On July 26, 2013, NPC issued a notice to redeem the $98.1 million on August 21, 2013, see Note 5, Long-Term Debt, of the Condensed Notes to Financial Statements.  In addition, NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of August 1, 2013, NPC has no borrowings on its revolving credit facility.  NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below).   NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013.  However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NPChas transitioned to slower growth, the amount of capital expenditures required has declined.  NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage and optimize its resources.  As a result, NPC anticipates that it will be able to meet short-term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.

However, if energy costs rise at a rapid rate or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and  Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.

During the six months ended June 30, 2013, NPC paid dividends to NVE of $80.0 million. On August 1, 2013, NPC declared a dividend to NVE of $25.0 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, environmental compliance, improvement and maintenance of facilities.  As discussed in Note 12, Commitments and Contingencies, of the Notes to Financial Statements in the 2012 Form 10-K, capital projects include NPC’s termination payment of Reid Gardner Generating Station unit 4 from CDWR, which is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.

 During the six months ended June 30, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.

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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, its revolving credit facility agreement, and the terms of certain NVE debt.  As of June 30, 2013, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility.  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 June 30, 2013, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.  In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details;
b.	Financial covenants within NPC’s financing agreements – Under the NPC Credit Agreement, 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 1.00.  Based on financial statements for the period ended June 30, 2013, NPC was in compliance with this covenant and could incur up to $2.8billion of additional indebtedness
	All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently 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 Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3billion.

   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 and NVE’s financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the NPC Indenture.

The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of June 30, 2013, $3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.7 billion of General and Refunding Mortgage Securities as of June 30, 2013.  That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Althoughspecific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt.  On May 22, 2013, Moody’s upgraded NPC’s ratings.  On May 30, 2013, Fitch and S&P upgraded NPC’s rating outlook from Stable to Positive.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NPC		Sr. Secured Debt	BBB+*	A3*	BBB+*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

                       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.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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 agreement is posted on the WSPP website.

Under these contracts, a material adverse change, which includes 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

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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 June 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $116.3 million payment or obligation to NPC.  These contracts qualify for the normal purchases and normal sales scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.

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, 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 a 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 June 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade.

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 in Note 6, Long Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K,  NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility is reduced for net 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC.  If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NPC.  As a result, NPC will be required to offer for purchase approximately $3.1 billion of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NPC is unable to determine the extent to which holders of these debt securities will accept such tender offers.The average interest rate under NPC’sdebt securities is approximately 6.42%.  To the extent that debt securities are tendered pursuant to the required tender offers, NPC intends to fund the purchases using a combination of internal funds, its revolving credit facility or the issuance of long-term debt.Furthermore, NPC is required to obtain consents from lenders under the terms of itsrevolving credit facilitybefore consummating the MidAmerican Merger.

Sierra Pacific Power Company

RESULTS OF OPERATIONS

SPPC recognized net income of $10.8 million for the three months ended June 30, 2013, compared to net income of $12.7 million for the same period in 2012.  During the six months ended June 30, 2013, SPPC recognized net income of approximately $32.7million compared to $31.3 million for the same period in 2012.

During the six months ended June 30, 2013, SPPC paid dividends to NVE of $20.0 million. On August 1, 2013, SPPC declared a dividend of $20.0 million 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 energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of SPPC.  For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013		2012			Variance	% Change
Operating Revenues:
	Electric	$	174,302	$	168,007	$	6,295	3.7 %	$	346,929	$	337,813	$	9,116	2.7 %
	Gas		20,208		19,544		664	3.4 %		59,937		65,466		(5,529)	(8.4)%
		$	194,510	$	187,551	$	6,959	3.7 %	$	406,866	$	403,279	$	3,587	0.9 %
Energy Costs:
	Fuel for power generation		44,733		31,327		13,406	42.8 %		86,450		67,813		18,637	27.5 %
	Purchased power		41,465		28,816		12,649	43.9 %		81,367		64,401		16,966	26.3 %
	Gas purchased for resale		17,274		9,492		7,782	82.0 %		54,894		41,109		13,785	33.5 %
	Deferred energy - electric - net		(16,963)		4,314		(21,277)	(493.2)%		(36,298)		(8,356)		(27,942)	334.4 %
	Deferred energy - gas - net		(5,976)		1,123		(7,099)	(632.1)%		(20,351)		(117)		(20,234)	17,294.0 %
Energy efficiency program costs			1,757		3,400		(1,643)	(48.3)%		3,635		7,051		(3,416)	(48.4)%
	Total Costs	$	82,290	$	78,472	$	3,818	4.9 %	$	169,697	$	171,901	$	(2,204)	(1.3)%
Cost by Segment:
	Electric	$	70,992	$	67,857	$	3,135	4.6 %	$	135,154	$	130,909	$	4,245	3.2 %
	Gas		11,298		10,615		683	6.4 %		34,543		40,992		(6,449)	(15.7)%
		$	82,290	$	78,472	$	3,818	4.9 %	$	169,697	$	171,901	$	(2,204)	(1.3)%
Gross Margin by Segment:
	Electric	$	103,310	$	100,150	$	3,160	3.2 %	$	211,775	$	206,904	$	4,871	2.4 %
	Gas		8,910		8,929		(19)	(0.2)%		25,394		24,474		920	3.8 %
Gross Margin		$	112,220	$	109,079	$	3,141	2.9 %	$	237,169	$	231,378	$	5,791	2.5 %

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Electric gross margin increased for the three and six months ended June 30, 2013, compared to the same periods in 2012 primarily due to increased customer usage and customer growth.  Partially offsetting the increase was a decrease in BTGR revenue. 

Gas gross margin for the three and six months ended June 30, 2013, compared to the same periods in 2012, did not change materially.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDs within SPPC’s service territory:

		Three Months Ended June 30,					Six Months Ended June 30,
		2013	2012	Variance	% Change		2013	2012	Variance	% Change
SPPC
	Heating	489	548	(59)	(10.8)	%	2,774	2,676	98.0	3.7	%
	Cooling	263	235	28	11.9	%	263	235	28.0	11.9	%

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

Electric Operating Revenue
			Three Months Ended June 30,							Six Months Ended June 30,
Operating Revenues:			2013		2012			Variance	% Change	2013		2012			Variance	% Change
	Residential		$	52,523	$	50,917	$	1,606	3.2  %	$	115,501	$	112,276	$	3,225	2.9  %
	Commercial			66,795		63,791		3,004	4.7  %		123,681		122,503		1,178	1.0  %
	Industrial			38,720		38,623		97	0.3  %		73,360		71,693		1,667	2.3  %
		Retail  Revenues		158,038		153,331		4,707	3.1  %		312,542		306,472		6,070	2.0  %
	Other			16,264		14,676		1,588	10.8  %		34,387		31,341		3,046	9.7  %
		Total Operating Revenues	$	174,302	$	168,007	$	6,295	3.7  %	$	346,929	$	337,813	$	9,116	2.7  %
Retail sales in thousands of MWhs
	Residential			494		470		24	5.1  %		1,123		1,070		53	5.0  %
	Commercial			766		724		42	5.8  %		1,417		1,383		34	2.5  %
	Industrial			724		687		37	5.4  %		1,391		1,320		71	5.4  %
Retail sales in thousands of MWhs				1,984		1,881		103	5.5  %		3,931		3,773		158	4.2  %
Average retail revenue per MWh			$	79.66	$	81.52	$	(1.86)	(2.3) %	$	79.51	$	81.23	$	(1.72)	(2.1) %

Retail revenue increased for the three months ended June 30, 2013, as compared to the same period in 2012, primarily due to a $5.5 million increase in customer usage primarily due to an increase in CDDs as outlined in the table above and $1.0 million of rate increases due to various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K). These increases were partially offset by $1.6 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to Financial Statementsin the 2012 Form 10-K).

For the three months ended June 30, 2013, the average number of residential and commercial customers increased 0.8% and 3.0%, respectively, while industrial customers decreased 0.9% compared to the same period in 2012.

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Retail revenue increased for the six months ended June 30, 2013, as compared to the same period in 2012, primarily due to a $7.4 million increase in customer usage primarily due to an unusually cold January and an unusually hot June. These increases were partially offset by $3.4 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K).

For the six months ended June 30, 2013, the average number of residential, commercial, and industrial customers increased 0.7%, 1.9%, and 0.9%, respectively, compared to the same period in 2012.

Electric operating revenues – Other increased for the three and six months ended June 30, 2013, compared to the same periods in 2012, primarily due to increasesof $1.4 million and $2.2 million, respectively, in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).

Gas Operating Revenue
			Three Months Ended June 30,							Six Months Ended June 30,
			2013		2012			Variance	% Change	2013		2012			Variance	% Change
Gas Operating Revenues:
	Residential		$	9,486	$	11,241	$	(1,755)	(15.6) %	$	32,031	$	37,799	$	(5,768)	(15.3) %
	Commercial			3,258		4,412		(1,154)	(26.2) %		11,977		15,378		(3,401)	(22.1) %
	Industrial			1,272		1,495		(223)	(14.9) %		3,550		4,209		(659)	(15.7) %
		Retail  Revenues		14,016		17,148		(3,132)	(18.3) %		47,558		57,386		(9,828)	(17.1) %
	Wholesale Revenues			5,465		1,640		3,825	233.2  %		10,790		6,470		4,320	66.8  %
	Miscellaneous			727		756		(29)	(3.8) %		1,589		1,610		(21)	(1.3) %
		Total Gas Revenues	$	20,208	$	19,544	$	664	3.4  %	$	59,937	$	65,466	$	(5,529)	(8.4) %
Retail sales in thousands of Dths
	Residential			1,205		1,263		(58)	(4.6) %		5,341		4,970		371	7.5  %
	Commercial			610		685		(75)	(10.9) %		2,686		2,565		121	4.7  %
	Industrial			264		247		17	6.9  %		797		723		74	10.2  %
Retail sales in thousands of Dths				2,079		2,195		(116)	(5.3) %		8,824		8,258		566	6.9  %
Average retail revenue per Dth			$	6.74	$	7.81	$	(1.07)	(13.7) %	$	5.39	$	6.95	$	(1.56)	(22.4) %

SPPC’s retail gas revenues decreased for the three months ended June 30, 2013, compared to the same period in 2012, primarily due to a $2.7 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K). Decreased usage primarily due to a decrease in HDDS, as shown in the table above, also contributed to the decrease in retail gas revenues.   

SPPC’s retail gas revenues decreased for the six months ended June 30, 2013, compared to the same period in 2012, primarily due to a $12.4 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K).The decrease was partially offset by a $2.2 million increase in customer usage due to an increase in HDDs, as shown in the table above.

Wholesale revenues increased for the three and six months ended June 30, 2013, compared to the same periods in 2012, primarily due to an increase in natural gas prices. 

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

• generation efficiency; and

• volatility of commodity prices

		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013		2012			Variance	% Change
Energy Costs:
	Fuel for power generation	$	44,733	$	31,327	$	13,406	42.8  %	$	86,450	$	67,813	$	18,637	27.5 %
	Purchased power		41,465		28,816		12,649	43.9  %		81,367		64,401		16,966	26.3 %
Total Energy Costs		$	86,198	$	60,143	$	26,055	43.3  %	$	167,817	$	132,214	$	35,603	26.9 %
MWhs
	MWhs Generated (in thousands)		1,102		1,138		(36)	(3.2) %		2,248		2,316		(68)	(2.9)%
	Purchased Power (in thousands)		1,149		1,049		100	9.5  %		2,254		2,060		194	9.4 %
Total MWhs			2,251		2,187		64	2.9  %		4,502		4,376		126	2.9 %
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	40.59	$	27.53	$	13.06	47.4  %	$	38.46	$	29.28	$	9.18	31.3 %
	Average cost per MWh of Purchased Power	$	36.09	$	27.47	$	8.62	31.4  %	$	36.10	$	31.26	$	4.84	15.5 %
	Average total cost per MWh	$	38.29	$	27.50	$	10.79	39.2  %	$	37.28	$	30.21	$	7.07	23.4 %

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Energy costs and average cost per MWh increased for the three and six months ended June 30, 2013, compared to the same period in 2012, primarily due to higher natural gas prices.

• Fuel for generation costs increased for the three months ended June 30, 2013, compared to the same period in 2012.  Approximately $16.4 million of the change is due to higher natural gas prices partially offset by a decrease in volume of approximately $3.0 million.  Fuel for generation costs increased for the six months ended June 30, 2013 compared to the same period in 2012.  Approximately $22.5 million of the change is due to higher natural gas prices partially offset by a decrease in volume of approximately $3.9 million. 

• Purchased power costs increased for the three months ended June 30, 2013 compared to the same period in 2012. Approximately $10.0 million of the increase is due to the availability of lower priced hydro power in 2012 and an increase in natural gas prices in 2013 and approximately $2.6 million is due to increased volume.  Volume increased due to decreased reliance on internal generation. Purchased power costs increased for the six months ended June 30, 2013 compared to the same period in 2012.  Approximately $11.2 million of the increase is due to the availability of lower priced hydro power in 2012 and an increase in natural gas prices in 2013 and approximately $5.8 million is due to increased volume.  Volume increased due to decreased reliance on internal generation. 

Gas Purchased for Resale
	Three Months Ended June 30,								Six Months Ended June 30,
	2013		2012			Variance	% Change		2013		2012			Variance	% Change
Gas purchased for resale	$	17,274	$	9,492	$	7,782	82.0	%	$	54,894	$	41,109	$	13,785	33.5	%
Gas purchased for resale (in thousands of Dths)		3,499		3,013		486	16.1	%		11,926		11,287		639	5.7	%
Average cost per Dth	$	4.94	$	3.15	$	1.79	56.8	%	$	4.60	$	3.64	$	0.96	26.4	%

Gas purchased for resale increased for the three months ended June 30, 2013,compared to the same period in 2012.  Approximately $5.4 million of the increase is due to higher natural gas prices and approximately $2.4 million is due to an increase in volume.  Volume increased primarily due to excess availability of gas. 

Gas purchased for resale increased for the six months ended June 30, 2013,compared to the same period in 2012.  Approximately $10.9 million of the increase is due higher natural gas prices and approximately $2.9 million is due to an increase in volume.  Volume increased primarily due to cooler weather in the first quarter. 

Deferred Energy
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013		2012			Variance	% Change
Deferred energy - electric - net	$	(16,963)	$	4,314	$	(21,277)	(493.2) %	$	(36,298)	$	(8,356)	$	(27,942)	334.4 %
Deferred energy - gas - net	$	(5,976)	$	1,123	$	(7,099)	(632.1) %	$	(20,351)	$	(117)	$	(20,234)	17,294.0 %
	$	(22,939)	$	5,437	$	(28,376)	(521.9) %	$	(56,649)	$	(8,473)	$	(48,176)	568.6 %

Deferred energy – electric for the three months ended June 30, 2013 and 2012include amortization of deferred energy of $(7.9) million and $(20.2) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy – electric balance are under-collections of amounts recoverable in rates of $(9.1) million in 2013 and over-collections of $24.5 million in 2012. 

Deferred energy – electric for the six months ended June 30, 2013and 2012 include amortization of deferred energy of$(19.2) million and $(45.7) million,respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy – electric balance are under-collections of amounts recoverable in rates of $(17.1) million in 2013 and over-collections of $37.4 million in 2012.

Deferred energy – gas for the three months ended June 30, 2013 and 2012include amortization of deferred energy of $(3.6) million and $(4.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy – gas balance are under-collections of amounts recoverable in rates of $(2.4) million in 2013 and over-collections of $5.4 million in 2012. 

Deferred energy – gas for the six months ended June 30, 2013and 2012 include amortization of deferred energy of$(17.0) million and $(17.7) million,respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy – gas balance are under-collections of amounts recoverable in rates of $(3.3) million in 2013 and over-collections of $17.6 million in 2012.

Deferred energy 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 also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013		2012			Variance	% Change
Energy efficiency program costs	$	1,757	$	3,400	$	(1,643)	(48.3) %	$	3,635	$	7,051	$	(3,416)	(48.4) %
Merger related costs	$	3,520		-	$	3,520	N/A %	$	3,520	$	-	$	3,520	N/A %
Other operating expenses	$	36,256	$	33,654	$	2,602	7.7  %	$	72,061	$	70,086	$	1,975	2.8  %
Maintenance	$	8,157	$	7,662	$	495	6.5  %	$	14,988	$	17,115	$	(2,127)	(12.4) %
Depreciation and amortization	$	28,479	$	27,185	$	1,294	4.8  %	$	55,820	$	53,057	$	2,763	5.2  %

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For the three and six months ended June 30, 2013 energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings.

As discussed further in Note 2, Merger Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement.  As a result of the MidAmerican Merger, SPPC incurred additional merger related fees and stock compensation costs for the three and six months ended June 30, 2013.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger. SPPC expects to incur additional merger related fees upon shareholder approval of the MidAmerican Merger, as well as, upon consummation of the MidAmerican Merger.

Other operating expense increased for the three months ended June 30, 2013, compared to the same period in 2012, primarily due to $1.7 million increase in rate case related expenses, $0.7 million increase in outside consulting fees, $0.6 million reduction in capitalized costs as a result of a decrease in construction activity, and a $0.6 million increase in power generation and miscellaneous general expenses. The increase was partially offset by a $1.6 million decrease in stock compensation costs due to additional vesting of stock awards in 2012.

Other operating expense increased for the six months ended June 30, 2013, compared to the same period in 2012, primarily due to $1.8 million increase in rate case related expenses, $1.1 million reduction in capitalized costs as a result of a decrease in construction activity, and $0.6 million increase in outside consulting fees. The increase was partially offset by a $0.8 million decrease in pension and benefit costs.

Maintenance expense increased for the threemonths ended June 30, 2013, compared to the same period in 2012, primarily due to $1.0 million of turbine maintenance at the Tracy Generating Station.   

Maintenance expense decreased for the six months ended June 30, 2013, compared to the same period in 2012, primarily due to $3.5 million of 2012 planned major outages at the Tracy and Valmy Generating Stations,partially offset by $1.5 million of 2013 turbine maintenance at the Tracy Generating Station.   

Depreciation and amortization increased by approximately $1.3 million and $2.8 million for the three and six months ended June 30, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.

Interest Expense
	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012			Variance	% Change	2013			2012		Variance	% Change
Interest expense
(net of AFUDC-debt: $276, $594, $570 and $1,010)	$	15,373	$	15,379	$	(6)	(0.0) %	$	30,898	$	32,352	$	(1,454)	(4.5) %

Interest expense is comparable to prior period for the three months ended June 30, 2013.

Interest expense decreased $1.5 million the six months ended June 30, 2013, as compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.6 million, offset by a decrease in AFUDC-debt of $0.4 million.  See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)
		Three Months Ended June 30,							Six Months Ended June 30,
		2013		2012			Variance	% Change	2013		2012			Variance	% Change
Interest income (expense) on
	regulatory items	$	165	$	(128)	$	293	(228.9) %	$	140	$	(314)	$	454	(144.6) %
AFUDC-equity		$	424	$	742	$	(318)	(42.9) %	$	947	$	1,261	$	(314)	(24.9) %
Other income		$	2,518	$	599	$	1,919	320.4  %	$	3,658	$	2,782	$	876	31.5  %
Other expense		$	(1,573)	$	(1,276)	$	(297)	23.3  %	$	(2,821)	$	(2,611)	$	(210)	8.0  %

Interest expense on regulatory items decreased for the three and six months ended June 30, 2013, compared to the same periods in 2012, primarily due to $1.0 million and $1.7 million, respectively, of decreases in interest on deferred energy as a result of lower over-collected balances in 2013, offset by $0.7 million and $1.0 million, respectively, of decreases in carrying charges on solar conservation programs. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances.

AFUDC-equity decreased slightly for the three and six months ended June 30, 2013, compared to the same period in 2012, primarily due to completion of various projects.

Other income increased for the three months ended June 30, 2013 compared to the same period in 2012, primarily due to a $1.9 million insurance settlement in 2013.

Other income increased for the six months ended June 30, 2013 compared to the same period in 2012, primarily due to a $1.9 million insurance settlement in 2013, offset by $1.1 million settlement with CA ISO in 2011 recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.

Other expense increased for the three and six months ended June 30, 2013 compared to the same period in 2012, due to several items, none of which are individually material.

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Analysis of Cash Flows

SPPC’s cash flows increased during the six months ended June 30, 2013, compared to the same period in 2012, due to an increase in cash from operating activities and a decrease in cash used by investing and financing activities.

Cash From Operating Activities

SPPC’s net cash flows from operating activities were $108.2 million and $90.9 million for the period ending June 30, 2013 and 2012, respectively. 

The increase in cash from operating activities was primarily due to:

• Reduced coal purchases of $21.6 million;

• Reduced expenditures on renewable programs of $16.4 million;

• Timing of payments for energy costs of $11.0 million; and

• Receipt of approximately $9 million in insurance proceeds related to a previous claim.

The increase in cash from operating activities was partially offset by:

• Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of $74.1 million, partially offset by reduced refunds to customers of $27.1 million; and

• Reduced EEPR collections of $3.8 million.

Cash Used By Investing Activities

SPPC’s net cash used by investing activities were $56.6 million and $78.7 million for the period ending June 30, 2013 and 2012, respectively. 

The decrease in cash used by investing activities was primarily due to:

• Reduced capital expenditure for the NV Energize project of$62 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $9.5 million.

Cash Used By Financing Activities

SPPC’s net cash flows used by financing activities were $20.4 million and $22.2 million for the period ending June 30, 2013 and 2012, respectively.  The decrease in cash used by financing activities is primarily due to reduced costs associated with the credit facility.

SPPC paid dividends of $20 million to NVE during each of the periods ending June 30, 2013 and 2012.

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.  Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of June 30, 2013 was as follows (in millions):

Available Liquidity as of June 30, 2013 (in millions)
			SPPC
Cash and Cash Equivalents			$	92.0
	Balance available on Revolving Credit Facility(1)			243.7
			$	335.7
(1)		As of August 1, 2013, SPPC had approximately $243.7 million available under its revolving credit facility which includes reductions for letters of credits.

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

SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.  To meet this maturing debt obligation, SPPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of August 1, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2013.  However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As SPPChas transitioned to slower growth, the amount of capital expenditures required has declined.  SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources.  As a result, SPPC anticipates that it will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.   To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.

52

However, if energy costs rise at a rapid rate, or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances,SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from 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.  Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the six months ended June 30, 2013, SPPC paid dividends to NVE of approximately $20.0 million.On August 1, 2013, SPPC declared a dividend to NVE of $20.0 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, environmental compliance, improvement, and maintenance of facilities.

During the six months ended June 30, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K except for in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN.  The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period.  However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million. 

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 June 30, 2013, 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 the 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 June 30, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350million; (2) to refinance up to approximately $598.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.  In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details.
b.	Financial covenants within SPPC’s financing agreements – Under the SPPC Credit Agreement, the Utility 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 1.00.  Based on financial statements for the period ended June 30, 2013, SPPC was in compliance with this covenant and could incur up to $1.0billion of additional indebtedness.
	All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently 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.
c.	Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3billion.

   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 and NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the SPPC Indenture.

The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of June 30, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $851 millionof additional General and Refunding Mortgage Securities as of June 30, 2013.  That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt.  On May 22, 2013, Moody’s upgraded SPPC’s ratings.  On May 30, 2013, Fitch and S&P upgraded SPPC’s rating outlook from Stable to Positive.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB+*	A3*	BBB+*
	*Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

53

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

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.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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.

Under these contracts, a material adverse change, which includes 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.  According to the net mark-to-market value as of June 30, 2013, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement.  These contracts qualify for the normal purchases and normal sales 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.

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. 

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.

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 in Note 6, Long Term Debt of the Notes to Financial Statements in the 2012 Form 10-K,  SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility is reduced for net 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC.  If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the financing agreements of SPPC contains a crossdefault 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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of SPPC.  As a result, SPPC will be required to offer for purchase approximately $951.7 million of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, SPPC is unable to determine the extent to which holders of these debt securities will accept such tender offers.The average interest rate under these debt securities is approximately 6.05% for SPPC.  To the extent that debt securities are tendered pursuant to the required tender offers, SPPC intends to fund the purchases using a combination of internal funds, SPPC’s revolving credit facility or the issuance of long-term debt.Furthermore, SPPC isrequired to obtain consents from lenders under the terms of its revolving credit facilitybefore consummating the MidAmerican Merger.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, and Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.

54

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2013, 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.  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):

					2013
					Expected Maturities
																									Fair
				2013			2014			2015			2016			2017		Thereafter			Total				Value
Long-Term Debt
	NVE
	Fixed Rate			$	-		$	195,000		$	-		$	-		$	-	$	315,000		$	510,000		$	564,060
		Average Interest Rate			-			2.56	%		-			-			-		6.25	%		4.84	%		-
	NPC
	Fixed Rate			$	-		$	125,000		$	250,000		$	210,000		$	-	$	2,545,000		$	3,130,000		$	3,705,847
		Average Interest Rate			-			7.38	%		5.88	%		5.95	%		-		6.47	%		6.42	%		-
	Variable Rate			$	98,100		$	-		$	-		$	-		$	-	$	75,675		$	173,775		$	170,737
		Average Interest Rate			0.60	%		-			-			-			-		0.55	%		0.58	%		-
	SPPC
	Fixed Rate			$	250,000		$	-		$	-		$	450,000		$	-	$	251,742		$	951,742		$	1,080,271
		Average Interest Rate			5.45	%		-			-			6.00	%		-		6.75	%		6.05	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-	$	214,675		$	214,675		$	185,176
		Average Interest Rate			-			-			-			-			-		0.55	%		0.55	%		-
			TOTAL DEBT	$	348,100		$	320,000		$	250,000		$	660,000		$	-	$	3,402,092		$	4,980,192		$	5,706,091

Commodity Price Risk

See the 2012 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, 2012.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties.  Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition.  The Utilities’ credit risk associated with trading counterparties was approximately $116.6 million as of June 30, 2013, which compares to balances of $98.6 million at March 30, 2013. The increase from March 30, 2013 is primarily due to the increase in forward prices of power during the second quarter of 2013.

ITEM 4.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 June 30, 2013, the registrants’ disclosure controls and procedures were effective.

(b)Change in internal controls over financial reporting.

There were no changes in the registrants’ internal controls over financial reporting in the second quarter of 2013 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal controls over financial reporting.

55

PART II  -  OTHER INFORMATION

ITEM 1.                      LEGAL PROCEEDINGS

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 2012 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 2012 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarter ended March 31, 2012, with the exception of the following:

Risks Related to NVE’s proposed MidAmerican Merger

We may be unable to satisfy the conditions or obtain the approvals required to complete the MidAmerican Merger.

On May 29, 2013, we entered into the MidAmerican Merger Agreement. The consummation of the MidAmerican Merger is subject to the satisfaction or waiver of the remaining specified closing conditions, including (i) the approval of the MidAmerican Merger by the holders of a majority of the outstanding shares of NVE common stock; and (ii) the receipt of regulatory approvals and consents required to consummate the MidAmerican Merger, including among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement.The  regulatory approvals required to consummate the MidAmerican Merger may not be obtained at all, may not be obtained on the proposed terms and schedules contemplated by the parties, and/or may impose conditions on the completion of the MidAmerican Merger or require changes to the terms of the MidAmerican Merger.  MEHC is not obligated to complete the MidAmerican Merger if the regulatory approvals include any conditions or restrictions that would reasonably be expected to have a “Burdensome Effect” as defined in the MidAmerican Merger Agreement.  Reference Note 2, Merger Related Activities,of the Condensed Notes to Financial Statements for the description of shareholder and regulatory approvals and required consents.

Failure to complete the MidAmerican Merger could negatively impact our common stock share price.

Failure to complete the MidAmerican Merger may negatively impact the future value of our common stock.  If the MidAmerican Merger is not completed, the market price of our common stock may decline to the extent that the current market price of our stock reflects a market assumption that the merger will be completed.  Additionally, if the MidAmerican Merger is not completed, we will have incurred significant costs, as well as the diversion of management.  A failure to complete the MidAmerican Merger may also result in negative publicity and a negative impression of us in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and our stock price.

Provisions in the MidAmerican Merger Agreement may deter alternative business combinations, and in the event that the proposedMidAmerican Merger is terminated prior to its completion, we could incur significant termination fees and other costs that may have a negative impact on our financial performance and results.

The MidAmerican Merger Agreement prohibits us from soliciting third party proposals relating to the acquisition of more than 20% of our consolidated assets or 20% of the issued and outstanding shares of our common stock.This prohibition, which includes payment of a termination fee under certain circumstances, could discourage a potential competing acquirer from considering or proposing an acquisition of all or a portion of NVE even if it were prepared to pay consideration with a higher per share market price than that proposed in the MidAmerican Merger Agreement.

In addition, the MidAmerican Merger Agreement provides for certain termination rights for both NVE and MEHC, and upon termination of the MidAmerican Merger Agreement under certain circumstances, we may be obligated to pay MEHC a termination fee of up to $169.7 million.If the MidAmerican Merger is not completed by May 29, 2014, either MEHC or NVE may terminate the MidAmerican Merger Agreement, unless the failure to complete the MidAmerican Merger resulted from the failure of the party seeking to terminate the MidAmerican Merger Agreement to perform its obligations.  The May 29, 2014 date may be extended by either party, but not beyond July 29, 2014, if the only unmet closing condition is the receipt of one or more governmental approvals.  If the MidAmerican Merger is not completed, in addition to the termination fee that may be payable, we will have incurred significant costs.

These provisions may deter third parties from proposing or pursuing alternative business combinations that might result in greater value to our shareholders than the MidAmerican Merger. 

The pending MidAmerican Merger may negatively impact our ability to recruit and retain key employees.

Employee retention and recruitment may be particularly challenging prior to the completion of the MidAmerican Merger, as employees and prospective employees may experience uncertainty about their future roles with the company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our business operations and financial results may be negatively affected.

Pending litigation against us could result in an injunction preventing the completion of the MidAmerican Merger and/or a judgment resulting in the payment of damages which may affect the financial results of operations.

Proposed class action lawsuits have been brought against us and our board of directors on behalf of our shareholders and may delay or prevent the MidAmerican Merger or increase its costs.  Reference Note 8, Commitments and Contingencies of the Condensed Notes to Financial Statements, for discussion of pending litigation related to the MidAmerican Merger.

We will be subject to representations, warranties, and covenants while the MidAmerican Merger is pending which could impact our financial performance and results.

The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both us and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice.  In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances or limitations on increasing our common stock dividend payout. 

56

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

Issuer Purchases of Equity Securities

The following table contains information about NVE’s purchases of common stock for the quarter ended June 30, 2013:

					Total Number of Shares	Maximum Number of
					Purchased as Part of	Shares that may yet be
		Total Number of	Average Price		Publicly Announced	Purchased Under the
Period		Shares Purchased (1)	Paid Per Share		Plans or Programs	Plans or Programs
April 1 - April 30, 2013		64,000	$	20.82	N/A	N/A
May 1 - May 31, 2013		64,000		20.98	N/A	N/A
June 1 - June 30, 2013		-		-	N/A	N/A
	Total	128,000	$	20.90	N/A	N/A
(1)	Represents shares of common stock purchased on the open market to provide shares to participants under various NVE stock compensation plans. These purchases were not made pursuant to a publicly announced stock repurchase plan or program.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.OTHER INFORMATION

None. 

57

ITEM 6.EXHIBITS

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

 (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.

(21)    NV Energy, Inc.:

Lands of Sierra Inc., a Nevada corporation

Nevada Power Company d/b/a NV Energy, a Nevada corporation

NVE Insurance Company, Inc., a Nevada corporation

Sierra Gas Holdings Company, a Nevada corporation

Sierra Pacific Power Company d/b/a NV Energy, a Nevada corporation

          Nevada Power Company:

Commonsite, Inc., a Nevada corporation

Nevada Electric Investment Company, a Nevada corporation

          Sierra Pacific Power Company:

GPSF-B Inc. , a Delaware corporation
Piñon Pine Corporation, a Nevada corporation
Piñon Pine Investment Company, a Nevada corporation
	Piñon Pine Company, L.L.C., a Nevada limited liability company

(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.

58

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

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Schema
101.CAL	XBRL Calculation Linkbase
101.LAB	XBRL Label Linkbase
101.PRE	XBRL Presentation Linkbase
101.DEF	XBRL Definition Linkbase

59

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:August 2, 2013	By:	/s/Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date:  August 2, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Nevada Power Company d/b/a NV Energy
	(Registrant)
Date:  August 2, 2013	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date:  August 2, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)
Date:  August 2, 2013	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date: August 2, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

60

EX-12.1

 

EXHIBIT 12.1
NV ENERGY, INC.
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
			Six Months Ended
			June 30,				Year Ended December 31,
			2013		2012		2012		2011		2010		2009		2008
EARNINGS AS DEFINED:
	Net Income		$	84,708	$	81,612	$	321,946	$	163,432	$	226,984	$	182,936	$	208,887
	Income tax expense			46,761		46,054		166,592		86,915		113,764		75,451		95,354
	Fixed Charges			153,545		159,063		312,801		343,719		363,773		360,896		335,868
	Capitalized Interest (allowance for
	borrowed funds used during construction)			(3,813)		(3,503)		(7,493)		(8,718)		(23,355)		(20,229)		(29,527)
		Total	$	281,201	$	283,226	$	793,846	$	585,348	$	681,166	$	599,054	$	610,582
FIXED CHARGES AS DEFINED:
	Interest Expensed and Capitalized (1)		$	153,545	$	159,063	$	312,801	$	343,719	$	363,773	$	360,896	$	335,868
		Total	$	153,545	$	159,063	$	312,801	$	343,719	$	363,773	$	360,896	$	335,868
RATIO OF EARNINGS TO FIXED
CHARGES				1.83		1.78		2.54		1.70		1.87		1.66		1.82

⁽¹⁾ Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income adjusted for income taxes and fixed charges excluding capitalized interest.   “Fixed Charges” represents the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed to be attributable to interest.

EX-12.2

 

EXHIBIT 12.2
NEVADA POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
			Six Months Ended
			June 30,				Year Ended December 31,
			2013		2012		2012		2011		2010		2009		2008
EARNINGS AS DEFINED:
	Net income		$	64,110	$	60,981	$	257,738	$	132,586	$	185,943	$	134,284	$	151,431
	Income tax expense			35,065		33,574		138,113		70,737		91,757		61,652		71,382
	Fixed Charges			108,295		111,754		220,470		233,788		240,830		247,290		210,067
	Capitalized Interest (allowance for
	borrowed funds used during construction)			(3,243)		(2,493)		(5,437)		(6,770)		(21,443)		(17,184)		(20,063)
		Total	$	204,227	$	203,816	$	610,884	$	430,341	$	497,087	$	426,042	$	412,817
FIXED CHARGES AS DEFINED:
	Interest Expensed and Capitalized (1)		$	108,295	$	111,754	$	220,470	$	233,788	$	240,830	$	247,290	$	210,067
		Total	$	108,295	$	111,754	$	220,470	$	233,788	$	240,830	$	247,290	$	210,067
RATIO OF EARNINGS TO FIXED
CHARGES				1.89		1.82		2.77		1.84		2.06		1.72		1.97

⁽¹⁾ Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net incomeadjusted for income taxes and fixed charges excluding capitalized interest.  “Fixed Charges” represents the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest. 

EX-12.3

 

EXHIBIT 12.3
SIERRA PACIFIC POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
			Six Months Ended
			June 30,				Year Ended December 31,
			2013		2012		2012		2011		2010		2009		2008
EARNINGS AS DEFINED:
	Net Income		$	32,680	$	31,323	$	84,354	$	59,886	$	72,375	$	73,085	$	90,582
	Income tax expense			16,656		17,075		40,221		31,197		40,404		31,225		37,603
	Fixed Charges			32,087		34,077		65,838		70,418		72,815		74,955		84,478
	Capitalized Interest (allowance for
	borrowed funds used during construction)			(570)		(1,010)		(2,056)		(1,948)		(1,912)		(3,044)		(9,464)
		Total	$	80,853	$	81,465	$	188,357	$	159,553	$	183,682	$	176,221	$	203,199
FIXED CHARGES AS DEFINED:
	Interest Expensed and Capitalized (1)		$	32,087	$	34,077	$	65,838	$	70,418	$	72,815	$	74,955	$	84,478
		Total	$	32,087	$	34,077	$	65,838	$	70,418	$	72,815	$	74,955	$	84,478
RATIO OF EARNINGS TO FIXED
CHARGES				2.52		2.39		2.86		2.27		2.52		2.35		2.41

⁽¹⁾ Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income adjusted for income taxes and fixed charges excluding capitalized interest.  “Fixed Charges” represents the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

EX-31.1

 

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of NV Energy, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

EX-31.2

 

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of Nevada Power Company (dba NV Energy);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.3

 

EXHIBIT 31.3

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of Sierra Pacific Power Company (dba NV Energy);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Michael W. Yackira

Michael W. Yackira

Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.4

 

EXHIBIT 31.4

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, Jonathan S. Halkyard, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of NV Energy, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

EX-31.5

 

EXHIBIT 31.5

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Jonathan S. Halkyard, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of Nevada Power Company (dba NV Energy);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

EX-31.6

 

EXHIBIT 31.6

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Jonathan S. Halkyard, certify that:

1.	I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2013 of Sierra Pacific Power Company (dba NV Energy);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 2, 2013

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

EX-32.1

 

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

 

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

 

EXHIBIT 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

 

EXHIBIT 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan S. Halkyard, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.5

 

EXHIBIT 32.5

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan S. Halkyard, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.6

 

EXHIBIT 32.6

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan S. Halkyard, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

August 2, 2013

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

XML

COMMON STOCK AND OTHER PAID-IN CAPITAL

6 Months Ended

Jun. 30, 2013

Equity [Abstract]

COMMON STOCK AND OTHER PAID-IN CAPITAL

NOTE 10.COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date		Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$	0.19	March 20, 2013	March 5, 2013
May 8, 2013	$	0.19	June 19, 2013	June 4, 2013
August 1, 2013	$	0.19	September 18, 2013	September 3, 2013

On August 1, 2013, NPC and SPPC declared dividends payable to NVE of $25.0 million and $20.0 million, respectively. For the six months ended June 30, 2013, NPC and SPPC paid dividends to NVE of $80.0 million and $20.0 million, respectively.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program. All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award. Treasury stock is accounted for using the cost method. During the six months ended June 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million. During the six months ended June 30, 2013, NVE re-issued 792,946 treasury shares to satisfy employee benefit plans.In May 2013, NVE ceased the repurchase of common stock as a result of the proposed MidAmerican Merger.

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 261,068	$ 298,271
Accounts receivable less allowance for uncollectible accounts	433,336	373,099
Materials, supplies and fuel, at average cost	130,747	138,337
Deferred energy costs - electric	30,122	0
Deferred energy costs - gas	991	0
Deferred income taxes	109,450	60,592
Other current assets	47,591	40,750
Total Current Assets	1,013,305	911,049
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	12,159,227	12,031,053
Construction work-in-progress	757,924	708,109
Total	12,917,151	12,739,162
Less accumulated provision for depreciation	3,448,469	3,313,188
Public Utilities, Property, Plant and Equipment, Net	9,468,682	9,425,974
Investments and other property, net	63,387	56,660
Other Assets, Noncurrent [Abstract]
Deferred energy	81,274	87,072
Regulatory assets	1,077,364	1,132,768
Regulatory asset for pension plans	274,200	281,195
Other Assets, Noncurrent	75,029	89,418
Total Deferred Charges and Other Assets	1,507,867	1,590,453
Assets	12,053,241	11,984,136
Current Liabilities:
Current maturities of long-term debt	480,018	356,283
Accounts Payable	333,588	332,245
Accrued expenses	119,245	127,693
Deferred energy	0	136,865
Other current liabilities	69,895	66,221
Total Current Liabilities	1,002,746	1,019,307
Long-term debt	4,543,733	4,669,798
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	1,564,260	1,470,973
Deferred investment tax credit	12,430	13,538
Accrued retirement benefits	167,793	162,260
Regulatory liabilities	583,217	550,687
Other deferred credits and liabilities	614,873	540,202
Total Deferred Credits and Other Liabilities	2,942,573	2,737,660
Shareholders' Equity
Common stock	236,000	236,000
Treasury stock, at cost	(8,542)	(16,804)
Other paid-in capital	2,715,358	2,712,943
Retained earnings	630,521	635,303
Accumulated other comprehensive loss	(9,148)	(10,071)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,564,189	3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	12,053,241	11,984,136
Nevada Power Company [Member]
Current Assets:
Cash and cash equivalents	141,686	201,202
Accounts receivable less allowance for uncollectible accounts	323,870	248,501
Materials, supplies and fuel, at average cost	77,488	77,675
Deferred energy costs - electric	27,389	0
Deferred income taxes	86,367	48,590
Other current assets	35,102	28,763
Total Current Assets	691,902	604,731
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	8,437,303	8,363,566
Construction work-in-progress	649,128	567,941
Total	9,086,431	8,931,507
Less accumulated provision for depreciation	2,143,914	2,035,322
Public Utilities, Property, Plant and Equipment, Net	6,942,517	6,896,185
Investments and other property, net	50,027	49,808
Other Assets, Noncurrent [Abstract]
Deferred energy	80,109	87,072
Regulatory assets	762,681	804,013
Regulatory asset for pension plans	133,409	136,682
Other Assets, Noncurrent	58,959	62,654
Total Deferred Charges and Other Assets	1,035,158	1,090,421
Assets	8,719,604	8,641,145
Current Liabilities:
Current maturities of long-term debt	229,743	106,048
Accounts Payable	212,133	201,193
Accounts Payable, Related Parties, Current	48,398	42,036
Accrued expenses	82,199	86,433
Deferred energy	0	86,102
Other current liabilities	55,326	52,567
Total Current Liabilities	627,799	574,379
Long-term debt	3,104,936	3,230,808
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	1,173,431	1,101,804
Deferred investment tax credit	4,126	4,688
Accrued retirement benefits	51,418	49,381
Regulatory liabilities	343,521	323,400
Other deferred credits and liabilities	507,751	434,367
Total Deferred Credits and Other Liabilities	2,080,247	1,913,640
Shareholders' Equity
Common stock	1	1
Other paid-in capital	2,308,211	2,308,211
Retained earnings	602,722	618,612
Accumulated other comprehensive loss	(4,312)	(4,506)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	2,906,622	2,922,318
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	8,719,604	8,641,145
Sierra Pacific Power Company [Member]
Current Assets:
Cash and cash equivalents	91,950	60,786
Accounts receivable less allowance for uncollectible accounts	109,324	124,464
Materials, supplies and fuel, at average cost	53,259	60,662
Deferred energy costs - electric	2,733	0
Deferred energy costs - gas	991	0
Intercompany income taxes receivable	10,351	10,351
Deferred income taxes	33,190	21,589
Other current assets	11,799	11,633
Total Current Assets	313,597	289,485
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	3,721,924	3,667,487
Construction work-in-progress	108,796	140,168
Total	3,830,720	3,807,655
Less accumulated provision for depreciation	1,304,555	1,277,866
Public Utilities, Property, Plant and Equipment, Net	2,526,165	2,529,789
Investments and other property, net	6,792	6,499
Other Assets, Noncurrent [Abstract]
Deferred energy	1,165	0
Regulatory assets	314,683	328,755
Regulatory asset for pension plans	137,050	140,268
Other Assets, Noncurrent	10,790	21,477
Total Deferred Charges and Other Assets	463,688	490,500
Assets	3,310,242	3,316,273
Current Liabilities:
Current maturities of long-term debt	250,275	250,235
Accounts Payable	85,323	106,415
Accounts Payable, Related Parties, Current	28,209	21,534
Accrued expenses	30,990	32,936
Deferred energy	0	50,763
Other current liabilities	14,570	13,655
Total Current Liabilities	409,367	475,538
Long-term debt	928,797	928,990
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	492,443	465,508
Deferred investment tax credit	8,304	8,850
Accrued retirement benefits	99,732	98,676
Regulatory liabilities	239,696	227,287
Other deferred credits and liabilities	80,370	72,688
Total Deferred Credits and Other Liabilities	920,545	873,009
Shareholders' Equity
Common stock	4	4
Other paid-in capital	1,111,266	1,111,266
Retained earnings	(58,306)	(70,986)
Accumulated other comprehensive loss	(1,431)	(1,548)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,051,533	1,038,736
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 3,310,242	$ 3,316,273

XML

MERGER RELATED ACTIVITIES

6 Months Ended

Jun. 30, 2013

Business combinations [Abstract]

MERGER RELATED ACTIVITIES

NOTE2.       MERGER RELATED ACTIVITIES

MidAmerican Merger

On May 29, 2013, NVE entered into the MidAmerican Merger Agreement. The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation in the MidAmerican Merger. Once merged, NVE will become an indirect wholly owned subsidiary of MEHC. The closing is expected to occur during the first quarter of 2014.

Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest and subject to applicable withholding taxes.

`       The MidAmerican Merger Agreement has been approved by the BOD of both NVE and MEHC, but the consummation of the MidAmerican Merger is subject to the satisfaction or waiver of specified closing conditions, including:

the approval of the MidAmerican Merger by the holders of a majority of the outstanding shares of NVE common stock (NVE filed a preliminary proxy statement with the SEC in July 2013);

the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings);

the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission had terminated the applicable waiting period under the Hart-Scott-Rodino Act. Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied;

the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and

other customary closing conditions.

The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions,to conduct our business in a manner substantially consistent with our current practice.  In addition, the covenants contain several restrictions that apply unless MEHC's consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances or limitations on increasing our common stock dividend payout. 

The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.

During the three and six month periods ending June 30, 2013, NVE incurred $13.6 million (pre-tax) of merger related fees and stock compensation costs related to the MidAmerican Merger which have been expensed and presented on the Statement of Comprehensive Income as Merger Related Costs. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation, upon announcement of the MidAmerican Merger. NVE expects to incur additional merger fees relating to the MidAmerican Merger, as well as, upon consummation of the MidAmerican Merger.

As a result of the pending MidAmerican Merger, NVE, its directors, Silver Merger Sub, Inc. and, in some cases, MEHC, have been named as defendants in certain lawsuits brought by alleged NVE shareholders seeking, among other things, to enjoin the proposed MidAmerican Merger; see Note 8, Commitments and Contingencies for further details. In addition, NVE has ceased the repurchase of any common stock for NVE stock compensation plans; see Note 10, Common Stock and Other Paid-In Capital.

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities. As a result, NVE, NPC and SPPC will be required to offer for purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these debt securities is approximately 6.25%, 6.42% and 6.05% for NVE, NPC and SPPC, respectively. To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities' revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities are required to obtain consents from lenders under the terms of the Utilities' revolving credit facilities and NVE's term loan before consummating the MidAmerican Merger.

One Company Merger between NPC and SPPC

As detailed further in Note 4, Regulatory Actions, NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.

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COMMON STOCK AND OTHER PAID-IN CAPITAL (Tables)

6 Months Ended

Jun. 30, 2013

Equity [Abstract]

Dividend Declarations

Declaration Date		Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$	0.19	March 20, 2013	March 5, 2013
May 8, 2013	$	0.19	June 19, 2013	June 4, 2013
August 1, 2013	$	0.19	September 18, 2013	September 3, 2013

XML

EARNINGS PER SHARE (NVE)

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

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.

			Three Months Ended June 30,				Six Months Ended June 30,
			2013		2012		2013		2012
Basic EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator
		Weighted average number of common shares outstanding		235,489,559		235,999,750		235,342,448		235,999,750
	Per Share Amounts
		Net Income per share - basic	$	0.27	$	0.29	$	0.36	$	0.35
Diluted EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator(1)
		Weighted average number of shares outstanding before dilution		235,489,559		235,999,750		235,342,448		235,999,750
		Stock options		58,916		38,237		38,842		36,760
		Non-Employee Director stock plan		185,335		160,257		182,653		156,972
		Employee stock purchase plan		2,719		2,725		6,672		6,807
		Restricted Shares		472,000		518,750		525,500		508,250
		Performance Shares		1,192,871		1,183,557		1,108,390		1,006,531
	Diluted Weighted Average Number of Shares			237,401,400		237,903,276		237,204,505		237,715,070
	Per Share Amounts
		Net income per share - diluted	$	0.27	$	0.29	$	0.36	$	0.34
	(1)	The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending June 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 330,322 shares, would be included for the three and six months ended June 30, 2012, respectively.

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EARNINGS PER SHARE (NVE) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 63,233		$ 69,439		$ 84,708		$ 81,612
Denominator
Weighted Average Shares of Common Stock Outstanding - basic	235,489,559		235,999,750		235,342,448		235,999,750
Per Share Amounts
Net income per share - basic	$ 0.27		$ 0.29		$ 0.36		$ 0.35
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 63,233		$ 69,439		$ 84,708		$ 81,612
Denominator
Weighted Average Number of Shares Outstanding, Basic	235,489,559		235,999,750		235,342,448		235,999,750
Stock options (in shares)	58,916		38,237		38,842		36,760
Non-Employee Director stock plan (in shares)	185,335		160,257		182,653		156,972
Employee stock purchase plan (in shares)	2,719		2,725		6,672		6,807
Restricted Shares (in shares)	472,000		518,750		525,500		508,250
Performance Shares (in shares)	1,192,871		1,183,557		1,108,390		1,006,531
Weighted Average Number of Shares Outstanding, Diluted	237,401,400	[1]	237,903,276	[1]	237,204,505	[1]	237,715,070	[1]
Per Share Amounts
Net income per share - diluted	$ 0.27		$ 0.29		$ 0.36		$ 0.34

[1] The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending June 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 330,322 shares, would be included for the three and six months ended June 30, 2012, respectively.

XML

SEGMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Operating Revenues	$ 731,638	$ 740,698	$ 1,315,860	$ 1,352,118
Energy Costs:
Fuel for power generation	188,979	112,585	336,227	229,620
Purchased power	170,861	164,092	292,171	281,208
Gas purchased for resale	17,274	9,492	54,894	41,109
Deferred energy	(86,687)	10,490	(165,752)	(1,249)
Energy efficiency program costs	12,599	24,600	22,444	44,025
Total Costs	303,026	321,259	539,984	594,713
Gross Margin	428,612	419,439	775,876	757,405
Merger related costs	13,552	0	13,552	0
Other Cost and Expense, Operating	106,798	103,371	211,470	206,972
Utilities Operating Expense, Maintenance	24,046	24,650	48,952	57,176
Depreciation, Depletion and Amortization, Nonproduction	98,884	96,316	194,886	187,178
Taxes, Other	15,846	14,266	32,322	28,775
Operating Income	169,486	180,836	274,694	277,304
Unallocated Amount to Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues	4	4	7	8
Energy Costs:
Total Costs	0	0	0	0
Gross Margin	4	4	7	8
Merger related costs	1,165		1,165
Other Cost and Expense, Operating	442	1,067	1,917	1,774
Taxes, Other	39	45	261	237
Operating Income	(1,642)	(1,108)	(3,336)	(2,003)
NPC Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues	537,124	553,143	908,987	948,831
Energy Costs:
Fuel for power generation	144,246	81,258	249,777	161,807
Purchased power	129,396	135,276	210,804	216,807
Deferred energy	(63,748)	5,053	(109,103)	7,224
Energy efficiency program costs	10,842	21,200	18,809	36,974
Total Costs	220,736	242,787	370,287	422,812
Gross Margin	316,388	310,356	538,700	526,019
Merger related costs	8,867		8,867
Other Cost and Expense, Operating	70,100	68,650	137,492	135,112
Utilities Operating Expense, Maintenance	15,889	16,988	33,964	40,061
Depreciation, Depletion and Amortization, Nonproduction	70,405	69,131	139,066	134,121
Taxes, Other	9,632	8,596	19,591	17,050
Operating Income	141,495	146,991	199,720	199,675
SPPC Total [Member]
Segment Reporting Information [Line Items]
Operating Revenues	194,510	187,551	406,866	403,279
Energy Costs:
Fuel for power generation	44,733	31,327	86,450	67,813
Purchased power	41,465	28,816	81,367	64,401
Gas purchased for resale	17,274	9,492	54,894	41,109
Deferred energy	(22,939)	5,437	(56,649)	(8,473)
Energy efficiency program costs	1,757	3,400	3,635	7,051
Total Costs	82,290	78,472	169,697	171,901
Gross Margin	112,220	109,079	237,169	231,378
Merger related costs	3,520		3,520
Other Cost and Expense, Operating	36,256	33,654	72,061	70,086
Utilities Operating Expense, Maintenance	8,157	7,662	14,988	17,115
Depreciation, Depletion and Amortization, Nonproduction	28,479	27,185	55,820	53,057
Taxes, Other	6,175	5,625	12,470	11,488
Operating Income	29,633	34,953	78,310	79,632
SPPC Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues	174,302	168,007	346,929	337,813
Energy Costs:
Fuel for power generation	44,733	31,327	86,450	67,813
Purchased power	41,465	28,816	81,367	64,401
Deferred energy	(16,963)	4,314	(36,298)	(8,356)
Energy efficiency program costs	1,757	3,400	3,635	7,051
Total Costs	70,992	67,857	135,154	130,909
Gross Margin	103,310	100,150	211,775	206,904
SPPC Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues	20,208	19,544	59,937	65,466
Energy Costs:
Gas purchased for resale	17,274	9,492	54,894	41,109
Deferred energy	(5,976)	1,123	(20,351)	(117)
Total Costs	11,298	10,615	34,543	40,992
Gross Margin	$ 8,910	$ 8,929	$ 25,394	$ 24,474

XML

MERGER RELATED ACTIVITIES (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Merger Related Activities [Line Items]
Merger related costs	$ 13,552,000	$ 0	$ 13,552,000	$ 0
Nevada Power Company [Member]
Merger Related Activities [Line Items]
Merger related costs	8,867,000	0	8,867,000	0
Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Merger related costs	3,520,000	0	3,520,000	0
MidAmerican Merger [Member]
Merger Related Activities [Line Items]
Merger Agreement Date			May 29, 2013
Expected Merger Closing Date			first quarter of 2014
Merger Closing Conditions			• the approval of the MidAmerican Merger by the holders of a majority of the outstanding shares of NVE common stock (NVE filed a preliminary proxy statement with the SEC in July 2013); • the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings); • the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission had terminated the applicable waiting period under the Hart-Scott-Rodino Act. Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied; • the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and • other customary closing conditions.
Merger Termination Right			The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.
Merger Termination Fee	169,700,000		169,700,000
Merger Share Exchange Ratio			$ 23.75
Filing Date of Preliminary Proxy			July 2013
Filing Date of PUCN filing			July 2013
Filing Date of FERC filing			July 2013
Satisfaction date of Hart Scott Rodino Condition			July 22, 2013
Change of Control Description of Debt			As a result, NVE, NPC and SPPC will be required to offer for purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.
Merger Restrictions			The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice. In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances or limitations on increasing our common stock dividend payout.
Merger Description			On May 29, 2013, NVE entered into the MidAmerican Merger Agreement. The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation in the MidAmerican Merger. Once merged, NVE will become an indirect wholly owned subsidiary of MEHC. The closing is expected to occur during the first quarter of 2014.
MidAmerican Merger [Member] | Parent Company [Member]
Merger Related Activities [Line Items]
Debt required to be tendered	315,000,000		315,000,000
Average interest rate of debt required to be tendered			6.25%
MidAmerican Merger [Member] | Nevada Power Company [Member]
Merger Related Activities [Line Items]
Debt required to be tendered	3,100,000,000		3,100,000,000
Average interest rate of debt required to be tendered			6.42%
MidAmerican Merger [Member] | Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Debt required to be tendered	$ 951,700,000		$ 951,700,000
Average interest rate of debt required to be tendered			6.05%
One Company Merger [Member] | Nevada Power Company [Member]
Merger Related Activities [Line Items]
Merger Description			NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.
One Company Merger [Member] | Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Merger Description			NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Billions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 5.7	$ 5.9
Nevada Power Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	3.9	4.1
Sierra Pacific Power Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1.3	$ 1.3

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REGULATORY, General Rate Cases (Details) (GRC [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
SPPC Gas [Member]
Summary of General Rate Case [Line Items]
Anticipated Effective Date of Rate Filing	January 1, 2014
Requested Increase Decrease In General Rates	$ 10.2
Percentage Overall Increase Decrease In General Rates	11.40%
Requested Rate Of Return	7.72%
Requested Return On Equity	10.35%
General Rate Case Hearing Date	October 2013
SPPC Electric [Member]
Summary of General Rate Case [Line Items]
Anticipated Effective Date of Rate Filing	January 1, 2014
Requested Increase Decrease In General Rates	$ (9.4)
Percentage Overall Increase Decrease In General Rates	(1.40%)
Requested Rate Of Return	7.74%
Requested Return On Equity	10.40%
General Rate Case Hearing Date	October 2013

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EARNINGS PER SHARE (NVE) (Tables)

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

			Three Months Ended June 30,				Six Months Ended June 30,
			2013		2012		2013		2012
Basic EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator
		Weighted average number of common shares outstanding		235,489,559		235,999,750		235,342,448		235,999,750
	Per Share Amounts
		Net Income per share - basic	$	0.27	$	0.29	$	0.36	$	0.35
Diluted EPS
	Numerator ($000)
		Net Income	$	63,233	$	69,439	$	84,708	$	81,612
	Denominator(1)
		Weighted average number of shares outstanding before dilution		235,489,559		235,999,750		235,342,448		235,999,750
		Stock options		58,916		38,237		38,842		36,760
		Non-Employee Director stock plan		185,335		160,257		182,653		156,972
		Employee stock purchase plan		2,719		2,725		6,672		6,807
		Restricted Shares		472,000		518,750		525,500		508,250
		Performance Shares		1,192,871		1,183,557		1,108,390		1,006,531
	Diluted Weighted Average Number of Shares			237,401,400		237,903,276		237,204,505		237,715,070
	Per Share Amounts
		Net income per share - diluted	$	0.27	$	0.29	$	0.36	$	0.34
	(1)	The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending June 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 330,322 shares, would be included for the three and six months ended June 30, 2012, respectively.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$ 84,708	$ 81,612
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	194,886	187,178
Deferred Income Taxes and Tax Credits	46,599	34,425
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(5,139)	(4,251)
Deferred energy	(162,179)	6,888
Amortization of other regulatory assets	85,882	75,711
Deferred rate increase	4,602	2,474
Other Noncash Income (Expense)	6,769	2,279
Changes in certain assets and liabilities:
Accounts receivable	(51,238)	(79,520)
Materials, supplies and fuel	7,771	(16,594)
Other current assets	(6,548)	1,518
Accounts payable	21,621	4,493
Increase (Decrease) in Pension and Postretirement Obligations	5,533	4,907
Other current liabilities	(4,535)	(4,875)
Other deferred assets	(2,400)	(2,700)
Other regulatory assets	(4,374)	10,058
Other deferred liabilities	6,185	(10,940)
Net Cash from Operating Activities	228,143	292,663
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(191,673)	(261,559)
Customer advances for construction	149	(847)
Contributions in aid of construction	27,975	45,106
Investments and other property - net	(5,005)	(128)
Net Cash used by Investing Activities	(168,554)	(217,428)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	(312)	130,590
Retirement of long-term debt	(2,459)	(158,201)
Sale of Common Stock	1,798	0
Common stock repurchased	(6,329)	0
Dividends paid	(89,490)	(70,800)
Net Cash from/(used by) Financing Activities	(96,792)	(98,411)
Net Increase in Cash and Cash Equivalents	(37,203)	(23,176)
Beginning Balance in Cash and Cash Equivalents	298,271	145,944
Ending Balance in Cash and Cash Equivalents	261,068	122,768
Cash paid during period for:
Interest	143,592	148,603
Income taxes	2	1
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	107,466	121,785
Issuance of treasury stock	12,793
Nevada Power Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	64,110	60,981
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	139,066	134,121
Deferred Income Taxes and Tax Credits	34,800	27,209
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(4,192)	(2,990)
Deferred energy	(106,527)	13,127
Amortization of other regulatory assets	47,490	36,659
Deferred rate increase	4,602	2,474
Other Noncash Income (Expense)	769	(213)
Changes in certain assets and liabilities:
Accounts receivable	(75,369)	(101,041)
Materials, supplies and fuel	368	(4,167)
Other current assets	(6,340)	3,159
Accounts payable	30,467	41,388
Increase (Decrease) in Pension and Postretirement Obligations	2,037	2,605
Other current liabilities	(1,238)	(3,342)
Other deferred assets	(990)	(1,973)
Other regulatory assets	(1,004)	24,720
Other deferred liabilities	541	(6,386)
Net Cash from Operating Activities	128,590	226,331
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(117,291)	(164,634)
Customer advances for construction	198	637
Contributions in aid of construction	10,118	25,383
Investments and other property - net	1,196	(144)
Net Cash used by Investing Activities	(105,779)	(138,758)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	(147)	132,083
Retirement of long-term debt	(2,180)	(157,491)
Dividends paid	(80,000)	(79,000)
Net Cash from/(used by) Financing Activities	(82,327)	(104,408)
Net Increase in Cash and Cash Equivalents	(59,516)	(16,835)
Beginning Balance in Cash and Cash Equivalents	201,202	65,887
Ending Balance in Cash and Cash Equivalents	141,686	49,052
Cash paid during period for:
Interest	101,242	105,973
Income taxes	1	1
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	86,745	98,358
Sierra Pacific Power Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	32,680	31,323
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	55,820	53,057
Deferred Income Taxes and Tax Credits	16,759	11,894
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(947)	(1,261)
Deferred energy	(55,652)	(6,239)
Amortization of other regulatory assets	38,270	38,957
Other Noncash Income (Expense)	3,171	1,772
Changes in certain assets and liabilities:
Accounts receivable	24,140	21,543
Materials, supplies and fuel	7,403	(12,427)
Other current assets	127	(1,285)
Accounts payable	(7,303)	(27,583)
Increase (Decrease) in Pension and Postretirement Obligations	1,056	936
Other current liabilities	(1,030)	(1,251)
Other deferred assets	(1,410)	(727)
Other regulatory assets	(3,370)	(14,662)
Other deferred liabilities	(1,548)	(3,173)
Net Cash from Operating Activities	108,166	90,874
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(74,382)	(96,925)
Customer advances for construction	(49)	(1,484)
Contributions in aid of construction	17,857	19,723
Investments and other property - net	16	16
Net Cash used by Investing Activities	(56,558)	(78,670)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	(165)	(1,446)
Retirement of long-term debt	(279)	(710)
Dividends paid	(20,000)	(20,000)
Net Cash from/(used by) Financing Activities	(20,444)	(22,156)
Net Increase in Cash and Cash Equivalents	31,164	(9,952)
Beginning Balance in Cash and Cash Equivalents	60,786	55,195
Ending Balance in Cash and Cash Equivalents	91,950	45,243
Cash paid during period for:
Interest	29,757	30,000
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	$ 20,721	$ 23,427

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (129)	$ (83)	$ (265)	$ (172)
Market value of risk management assets and liabilities	3	123	(107)	264
Unrealized net gain/(loss) on investments	31	0	31	0
Nevada Power Company [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(50)	(38)	(104)	(70)
Sierra Pacific Power Company [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (32)	$ (23)	$ (63)	$ (46)

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SEGMENT INFORMATION

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

NOTE 3.SEGMENT INFORMATION

The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada 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 and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities. See Note 1, Summary of Significant Accounting Policies,of the Notes to Financial Statements in the 2012 Form 10-K for further information regarding energy efficiency program costs.

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
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	731,638	$	4	$	537,124	$	194,510	$	174,302	$	20,208
Energy Costs:
	Fuel for power generation		188,979		-		144,246		44,733		44,733		-
	Purchased power		170,861		-		129,396		41,465		41,465		-
	Gas purchased for resale		17,274		-		-		17,274		-		17,274
	Deferred energy		(86,687)		-		(63,748)		(22,939)		(16,963)		(5,976)
Energy efficiency program costs			12,599		-		10,842		1,757		1,757		-
Total Costs		$	303,026	$	-	$	220,736	$	82,290	$	70,992	$	11,298
Gross Margin		$	428,612	$	4	$	316,388	$	112,220	$	103,310	$	8,910
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			106,798		442		70,100		36,256
Maintenance			24,046		-		15,889		8,157
Depreciation and amortization			98,884		-		70,405		28,479
Taxes other than income			15,846		39		9,632		6,175
Operating Income (Loss)		$	169,486	$	(1,642)	$	141,495	$	29,633

Six Months Ended
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,315,860	$	7	$	908,987	$	406,866	$	346,929	$	59,937
Energy Costs:
	Fuel for power generation		336,227		-		249,777		86,450		86,450		-
	Purchased power		292,171		-		210,804		81,367		81,367		-
	Gas purchased for resale		54,894		-		-		54,894		-		54,894
	Deferred energy		(165,752)		-		(109,103)		(56,649)		(36,298)		(20,351)
Energy efficiency program costs			22,444		-		18,809		3,635		3,635		-
Total Costs		$	539,984	$	-	$	370,287	$	169,697	$	135,154	$	34,543
Gross Margin		$	775,876	$	7	$	538,700	$	237,169	$	211,775	$	25,394
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			211,470		1,917		137,492		72,061
Maintenance			48,952		-		33,964		14,988
Depreciation and amortization			194,886		-		139,066		55,820
Taxes other than income			32,322		261		19,591		12,470
Operating Income (Loss)		$	274,694	$	(3,336)	$	199,720	$	78,310

Three Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	740,698	$	4	$	553,143	$	187,551	$	168,007	$	19,544
Energy Costs:
	Fuel for power generation		112,585		-		81,258		31,327		31,327		-
	Purchased power		164,092		-		135,276		28,816		28,816		-
	Gas purchased for resale		9,492		-				9,492		-		9,492
	Deferred energy		10,490		-		5,053		5,437		4,314		1,123
Energy efficiency program costs			24,600		-		21,200		3,400		3,400		-
Total Costs		$	321,259	$	-	$	242,787	$	78,472	$	67,857	$	10,615
Gross Margin		$	419,439	$	4	$	310,356	$	109,079	$	100,150	$	8,929
Other operating expenses			103,371		1,067		68,650		33,654
Maintenance			24,650		-		16,988		7,662
Depreciation and amortization			96,316		-		69,131		27,185
Taxes other than income			14,266		45		8,596		5,625
Operating Income (Loss)		$	180,836	$	(1,108)	$	146,991	$	34,953

Six Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,352,118	$	8	$	948,831	$	403,279	$	337,813	$	65,466
Energy Costs:
	Fuel for power generation		229,620		-		161,807		67,813		67,813		-
	Purchased power		281,208		-		216,807		64,401		64,401		-
	Gas purchased for resale		41,109		-		-		41,109		-		41,109
	Deferred Energy		(1,249)		-		7,224		(8,473)		(8,356)		(117)
Energy efficiency program costs			44,025		-		36,974		7,051		7,051		-
Total Costs		$	594,713	$	-	$	422,812	$	171,901	$	130,909	$	40,992
Gross Margin		$	757,405	$	8	$	526,019	$	231,378	$	206,904	$	24,474
Other operating expenses			206,972		1,774		135,112		70,086
Maintenance			57,176		-		40,061		17,115
Depreciation and amortization			187,178		-		134,121		53,057
Taxes other than income			28,775		237		17,050		11,488
Operating Income (Loss)		$	277,304	$	(2,003)	$	199,675	$	79,632

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE1.    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, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., 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 2012 Form 10-K.

       The results of operations and cash flows of NVE, NPC and SPPC for the six months ended June 30, 2013, are not necessarily indicative of the results to be expected for the full year.

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary 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 June 30, 2013, 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.

Recent Accounting Standards Update

Derivatives and Hedging (ASC815)

In July 2013, the FASB amended its existing guidance related to hedge accounting. The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR. The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. NVE and the Utilities do not expect this amendment to have a material impact on their financial statements or disclosure requirements.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements. FASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists. As a result, there is diversity in practice in the presentation of unrecognized tax benefits. The objective of the amendment is to eliminate the diversity in practice, requiring the unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions. The amendment will be applied prospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities. NVE and the Utilities are evaluating the potential effects of this amendment and currently do not anticipate that the adoption of this amendment will have a material impact on the presentation of NVE and the Utilities' consolidated financial statements.

Other Comprehensive Income (ASC 220)

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income. In February 2013, the FASB reinstated certain portions of the deferred amendment. The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

Balance Sheet Offsetting Disclosures (ASC 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements. The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have a material impact on the disclosure requirements for NVE and the Utilities.

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REGULATORY ACTIONS, Deferred Energy (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013		Dec. 31, 2012
Nevada Deferred Energy
Nevada Deferred Energy Balance at period end	$ 17,284
Amortization	94,134
Cumulative balance as filed	(151,880)
Deferred Energy Under Collection	75,030	[1]
Reinstatement of deferred energy (effective 6/07, 10 years)	95,103
Total Deferred Energy	112,387
Deferred Assets
Deferred energy	81,274		87,072
Deferred Energy Electric Current	30,122		0
Deferred Energy Gas Current	991		0
Current Liabilities
Deferred energy	0		136,865
NPC Electric [Member]
Nevada Deferred Energy
Nevada Deferred Energy Balance at period end	12,395
Amortization	57,887
Cumulative balance as filed	(101,117)
Deferred Energy Under Collection	55,625	[1]
Reinstatement of deferred energy (effective 6/07, 10 years)	95,103
Total Deferred Energy	107,498
Deferred Assets
Deferred energy	80,109
Deferred Energy Electric Current	27,389
SPPC Electric [Member]
Nevada Deferred Energy
Nevada Deferred Energy Balance at period end	2,733
Amortization	19,196
Cumulative balance as filed	(32,693)
Deferred Energy Under Collection	16,230	[1]
Reinstatement of deferred energy (effective 6/07, 10 years)	0
Total Deferred Energy	2,733
Deferred Assets
Deferred Energy Electric Current	2,733
SPPC Gas [Member]
Nevada Deferred Energy
Nevada Deferred Energy Balance at period end	2,156
Amortization	17,051
Cumulative balance as filed	(18,070)
Deferred Energy Under Collection	3,175	[1]
Reinstatement of deferred energy (effective 6/07, 10 years)	0
Total Deferred Energy	2,156
Deferred Assets
Deferred energy	1,165
Deferred Energy Gas Current	$ 991

[1] These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant AccountingPolicies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K.

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REGULATORY ACTIONS, FERC Matters (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Nevada Power Company [Member] | FERC Filing 2012 [Member]
FERC Matters [Abstract]
TransmissionRateCase	$ 11.3
Transmission Rate Case Filing Date	October 2012
Anticipated Effective Date of Rate Filing	June 1, 2013
Nevada Power Company [Member] | FERC Filing 2013 [Member]
FERC Matters [Abstract]
Transmission Rate Case Filing Date	May 2013
Anticipated Effective Date of Rate Filing	January 1, 2014
Intervenor Filing Date	July 16, 2013
Sierra Pacific Power Company [Member] | FERC Filing 2012 [Member]
FERC Matters [Abstract]
TransmissionRateCase	$ 1.5
Transmission Rate Case Filing Date	October 2012
Anticipated Effective Date of Rate Filing	June 1, 2013
Sierra Pacific Power Company [Member] | FERC Filing 2013 [Member]
FERC Matters [Abstract]
Transmission Rate Case Filing Date	May 2013
Anticipated Effective Date of Rate Filing	January 1, 2014
Intervenor Filing Date	July 16, 2013

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COMMITMENTS AND CONTINGENCIES, Litigation Contingencies and Other Commitments (Details) (USD $)	6 Months Ended
	Jun. 30, 2013 MW
Capital Projects [Member]
ON Line TUA [Abstract]
Capacity of interconnection (in kV)	500
Utilities' aggregate share in transmission line project (in hundredths)	25.00%
GBT-South's share in the ON Line project (in hundredths)	75.00%
Nevada Power Company [Member]
Royalty claim [Abstract]
Damages sought in DC Lawsuit	$ 600,000,000
Minimum punitive damages sought in DC Lawsuit	1,000,000,000
Nevada Power Company [Member] | Capital Projects [Member]
ON Line TUA [Abstract]
Capitalized construction costs	336,100,000
Sierra Pacific Power Company [Member]
Farad Dam [Abstract]
Number of hydro generating units sold	four
Total capacity of hydro generating units sold (in MW)	10.3
Proceeds from sale of hydro units	8,000,000
Capacity of the Farad Hydro generating unit (in MW)	2.8
Estimate to rebuild diversion dam of the Farad Hydro generating unit	20,000,000
Amount entitled to be recovered for costs incurred to date on Farad Dam	4,000,000
Duration to rebuild the Farad dam from the date of the Court's decision	three years
ReplacementCost	19,800,000
Sierra Pacific Power Company [Member] | Capital Projects [Member]
ON Line TUA [Abstract]
Capitalized construction costs	$ 20,700,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
OTHER INCOME (EXPENSE):
AFUDC-debt	$ 1,682	$ 1,908	$ 3,813	$ 3,503
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(129)	(83)	(265)	(172)
Market value of risk management assets and liabilities	3	123	(107)	264
Unrealized net gain/(loss) on investments	31	0	31	0
Nevada Power Company [Member]
OTHER INCOME (EXPENSE):
AFUDC-debt	1,406	1,314	3,243	2,493
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(50)	(38)	(104)	(70)
Sierra Pacific Power Company [Member]
OTHER INCOME (EXPENSE):
AFUDC-debt	276	594	570	1,010
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (32)	$ (23)	$ (63)	$ (46)

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FAIR VALUE OF FINANCIAL INSTRUMENTS

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

NOTE 6. FAIR VALUE OF FINANCIAL INSTRUMENTS

The June 30, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in the Rabbi Trust continue to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE's consolidated long-term debt at June 30, 2013, is estimated to be $5.7 billion 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 was estimated to be $5.9 billion as of December 31, 2012.

The total fair value of NPC's consolidated long-term debt at June 30, 2013, is estimated to be $3.9 billion 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 was estimated to be $4.1 billion at December 31, 2012.

The total fair value of SPPC's consolidated long-term debt at June 30, 2013, is estimated to be $1.3 billion 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 was estimated to be $1.3 billion as of December 31, 2012.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 7,150	$ 8,748
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common stock, shares authorized (in shares)	350,000,000	350,000,000
Common stock, shares issued (in shares)	235,999,750	235,999,750
Common stock, shares outstanding (in shares)	235,546,924	235,079,156
Treasury stock (in shares)	452,826	920,594
Nevada Power Company [Member]
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	6,211	7,622
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares issued (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	1,000	1,000
Sierra Pacific Power Company [Member]
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 939	$ 1,126
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 3.75	$ 3.75
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares issued (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	1,000	1,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
OPERATING REVENUES:
OPERATING REVENUES	$ 731,638		$ 740,698		$ 1,315,860		$ 1,352,118
Operating Expenses
Fuel for power generation	188,979		112,585		336,227		229,620
Purchased power	170,861		164,092		292,171		281,208
Gas purchased for resale	17,274		9,492		54,894		41,109
Deferred energy	(86,687)		10,490		(165,752)		(1,249)
Merger related costs	13,552		0		13,552		0
Energy efficiency program costs	12,599		24,600		22,444		44,025
Other operating expenses	106,798		103,371		211,470		206,972
Maintenance	24,046		24,650		48,952		57,176
Depreciation and amortization	98,884		96,316		194,886		187,178
Taxes other than income	15,846		14,266		32,322		28,775
Total Operating Expenses	562,152		559,862		1,041,166		1,074,814
OPERATING INCOME	169,486		180,836		274,694		277,304
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(73,530)		(74,564)		(146,867)		(152,495)
Interest income (expense) on regulatory items	(16)		(1,977)		(843)		(4,179)
AFUDC - equity	2,250		2,319		5,139		4,251
Other income	3,813		6,291		7,633		10,485
Other expense	(4,036)		(4,640)		(8,287)		(7,700)
Total Other Income (Expense)	(71,519)		(72,571)		(143,225)		(149,638)
Income Before Income Tax Expense	97,967		108,265		131,469		127,666
Income Tax Expense (Benefit)	34,734		38,826		46,761		46,054
NET INCOME	63,233		69,439		84,708		81,612
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	246		154		492		309
Change in market value of risk management assets and liabilities	297		(229)		496		(475)
Unrealized net gain/(loss) on investment	(65)		0		(65)		0
OTHER COMPREHENSIVE INCOME(LOSS)	478		(75)		923		(166)
COMPREHENSIVE INCOME	63,711		69,364		85,631		81,446
Amount per share basic and diluted
Net income per share - basic	$ 0.27		$ 0.29		$ 0.36		$ 0.35
Net income per share - diluted	$ 0.27		$ 0.29		$ 0.36		$ 0.34
Weighted Average Shares of Common Stock Outstanding - basic	235,489,559		235,999,750		235,342,448		235,999,750
Weighted Average Shares of Common Stock Outstanding - diluted	237,401,400	[1]	237,903,276	[1]	237,204,505	[1]	237,715,070	[1]
Dividends Declared Per Share of Common Stock	$ 0.19		$ 0.17		$ 0.38		$ 0.30
Nevada Power Company [Member]
OPERATING REVENUES:
OPERATING REVENUES	537,124		553,143		908,987		948,831
Operating Expenses
Fuel for power generation	144,246		81,258		249,777		161,807
Purchased power	129,396		135,276		210,804		216,807
Deferred energy	(63,748)		5,053		(109,103)		7,224
Merger related costs	8,867		0		8,867		0
Energy efficiency program costs	10,842		21,200		18,809		36,974
Other operating expenses	70,100		68,650		137,492		135,112
Maintenance	15,889		16,988		33,964		40,061
Depreciation and amortization	70,405		69,131		139,066		134,121
Taxes other than income	9,632		8,596		19,591		17,050
Total Operating Expenses	395,629		406,152		709,267		749,156
OPERATING INCOME	141,495		146,991		199,720		199,675
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(51,643)		(52,602)		(102,902)		(107,007)
Interest income (expense) on regulatory items	(181)		(1,849)		(983)		(3,865)
AFUDC - equity	1,826		1,577		4,192		2,990
Other income	978		5,392		3,382		7,101
Other expense	(1,833)		(2,993)		(4,234)		(4,339)
Total Other Income (Expense)	(50,853)		(50,475)		(100,545)		(105,120)
Income Before Income Tax Expense	90,642		96,516		99,175		94,555
Income Tax Expense (Benefit)	31,977		34,219		35,065		33,574
NET INCOME	58,665		62,297		64,110		60,981
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	97		64		194		127
COMPREHENSIVE INCOME	58,762		62,361		64,304		61,108
Sierra Pacific Power Company [Member]
OPERATING REVENUES:
Electric	174,302		168,007		346,929		337,813
Gas	20,208		19,544		59,937		65,466
OPERATING REVENUES	194,510		187,551		406,866		403,279
Operating Expenses
Fuel for power generation	44,733		31,327		86,450		67,813
Purchased power	41,465		28,816		81,367		64,401
Gas purchased for resale	17,274		9,492		54,894		41,109
Deferral of energy - electric-net	(16,963)		4,314		(36,298)		(8,356)
Deferral of energy - gas-net	(5,976)		1,123		(20,351)		(117)
Merger related costs	3,520		0		3,520		0
Energy efficiency program costs	1,757		3,400		3,635		7,051
Other operating expenses	36,256		33,654		72,061		70,086
Maintenance	8,157		7,662		14,988		17,115
Depreciation and amortization	28,479		27,185		55,820		53,057
Taxes other than income	6,175		5,625		12,470		11,488
Total Operating Expenses	164,877		152,598		328,556		323,647
OPERATING INCOME	29,633		34,953		78,310		79,632
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(15,373)		(15,379)		(30,898)		(32,352)
Interest income (expense) on regulatory items	165		(128)		140		(314)
AFUDC - equity	424		742		947		1,261
Other income	2,518		599		3,658		2,782
Other expense	(1,573)		(1,276)		(2,821)		(2,611)
Total Other Income (Expense)	(13,839)		(15,442)		(28,974)		(31,234)
Income Before Income Tax Expense	15,794		19,511		49,336		48,398
Income Tax Expense (Benefit)	5,018		6,832		16,656		17,075
NET INCOME	10,776		12,679		32,680		31,323
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	58		43		117		85
COMPREHENSIVE INCOME	$ 10,834		$ 12,722		$ 32,797		$ 31,408

[1] The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending June 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 330,322 shares, would be included for the three and six months ended June 30, 2012, respectively.

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REGULATORY ACTIONS, Merger Related and Financing Application (Details) (USD $)	6 Months Ended
	Jun. 30, 2013
Nevada Power Company [Member]
Merger Related Activities [Line Items]
Financing Application Date	May 2013
New Authority Requested	$ 705,000,000
Amount Of Requested New Debt Consolidated Authority	1,100,000,000
Amount Of Requested Refinance Consolidated Authority	1,500,000,000
Amount Of Existing Revolver	1,300,000,000
Additional Authority Requested If Extended	255,000,000
Financing Application Hearing Date	August 2013
Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Financing Application Date	May 2013
New Authority Requested	705,000,000
Amount Of Requested New Debt Consolidated Authority	1,100,000,000
Amount Of Requested Refinance Consolidated Authority	1,500,000,000
Amount Of Existing Revolver	$ 600,000,000
MidAmerican Merger [Member] | Nevada Power Company [Member]
Merger Related Activities [Line Items]
Filing Date of PUCN filing	July 2013
Filing Date of FERC filing	July 12, 2013
Expected Authorization Date FERC	December 19, 2013
Expected Authorization Date PUCN	January 2014
Days To Respond	180 days
AdditionalDaysToRespond	180 days
MidAmerican Merger [Member] | Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Filing Date of PUCN filing	July 2013
Filing Date of FERC filing	July 12, 2013
Expected Authorization Date FERC	December 19, 2013
Expected Authorization Date PUCN	January 2014
Days To Respond	180 days
AdditionalDaysToRespond	180 days
One Company Merger [Member] | Nevada Power Company [Member]
Merger Related Activities [Line Items]
Filing Date of PUCN filing	May 2013
Filing Date of FERC filing	May 2013
Expected Authorization Date FERC	December 1, 2013
Expected Hearing Date	Feb. 01, 2014
Days To Respond	180 days
AdditionalDaysToRespond	180 days
One Company Merger [Member] | Sierra Pacific Power Company [Member]
Merger Related Activities [Line Items]
Filing Date of PUCN filing	May 2013
Filing Date of FERC filing	May 2013
Expected Authorization Date FERC	December 1, 2013
Expected Hearing Date	Feb. 01, 2014
Days To Respond	180 days
AdditionalDaysToRespond	180 days

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RETIREMENT PLAN AND POST-RETIREMENT BENEFITS (Tables)

6 Months Ended

Jun. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

NVE
	Pension Benefits					Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,132	$	4,406	$	660	$	595
Interest cost		9,303		10,228		1,677		1,905
Expected return on plan assets		(12,708)		(12,447)		(1,687)		(1,563)
Amortization of prior service cost		(720)		(724)		(952)		(987)
Amortization of net loss		4,797		3,473		890		731
Net periodic benefit cost	$	5,804	$	4,936	$	588	$	681
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	10,264	$	8,813	$	1,320	$	1,191
Interest cost		18,607		20,456		3,353		3,810
Expected return on plan assets		(25,416)		(24,894)		(3,373)		(3,126)
Amortization of prior service cost		(1,441)		(1,448)		(1,905)		(1,974)
Amortization of net loss		9,594		6,945		1,781		1,462
Net periodic benefit cost	$	11,608	$	9,872	$	1,176	$	1,363
The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.6% and 34.6%, respectively.

NPC
	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	2,761	$	2,358	$	389	$	350
Interest cost		4,453		4,881		556		602
Expected return on plan assets		(6,270)		(6,237)		(631)		(592)
Amortization of prior service cost		(453)		(456)		(23)		229
Amortization of net loss		2,117		1,363		289		221
Net periodic benefit cost	$	2,608	$	1,909	$	580	$	810
	Pension Benefits				Other Postretirement Benefits
		For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,522	$	4,715	$	778	$	700
Interest cost		8,905		9,762		1,111		1,205
Expected return on plan assets		(12,540)		(12,474)		(1,261)		(1,183)
Amortization of prior service cost		(905)		(912)		(46)		458
Amortization of net loss		4,234		2,726		578		441
Net periodic benefit cost	$	5,216	$	3,817	$	1,160	$	1,621
The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.7% and 36.6%, respectively.

SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended June 30,				For the Three Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	1,926	$	1,695	$	251	$	227
Interest cost		4,558		5,043		1,104		1,283
Expected return on plan assets		(6,162)		(5,937)		(1,022)		(941)
Amortization of prior service cost		(277)		(277)		(933)		(1,220)
Amortization of net loss		2,501		2,026		592		504
Net periodic benefit cost	$	2,546	$	2,550	$	(8)	$	(147)
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	3,852	$	3,391	$	501	$	455
Interest cost		9,117		10,086		2,207		2,566
Expected return on plan assets		(12,324)		(11,875)		(2,043)		(1,882)
Amortization of prior service cost		(554)		(554)		(1,866)		(2,439)
Amortization of net loss		5,001		4,052		1,185		1,007
Net periodic benefit cost	$	5,092	$	5,100	$	(16)	$	(293)
The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 35.6% and 34.5%, respectively.

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COMMON STOCK AND OTHER PAID-IN CAPITAL (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Dividends Payable [Line Items]
Dividends Declared Per Share of Common Stock	$ 0.19	$ 0.19	$ 0.19	$ 0.17	$ 0.38	$ 0.30
Common stock repurchased					$ (6,329)
Treasury stock [Member]
Dividends Payable [Line Items]
Common stock repurchaed (shares)					(325,178)
Common stock repurchased					$ (6,329)
Dividend Reinvestment and Employee Benefits (in shares)					792,946

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RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Components of Net Periodic Cost and Expected Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
United States Pension Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	$ 5,132	$ 4,406	$ 10,264	$ 8,813
Interest cost	9,303	10,228	18,607	20,456
Expected return on plan assets	(12,708)	(12,447)	(25,416)	(24,894)
Amortization of:
Prior service (credit)/cost	(720)	(724)	(1,441)	(1,448)
Actuarial (gain)/loss	4,797	3,473	9,594	6,945
Total net benefit cost	5,804	4,936	11,608	9,872
United States Postretirement Benefit Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	660	595	1,320	1,191
Interest cost	1,677	1,905	3,353	3,810
Expected return on plan assets	(1,687)	(1,563)	(3,373)	(3,126)
Amortization of:
Prior service (credit)/cost	(952)	(987)	(1,905)	(1,974)
Actuarial (gain)/loss	890	731	1,781	1,462
Total net benefit cost	588	681	1,176	1,363
Nevada Power Company [Member] | United States Pension Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	2,761	2,358	5,522	4,715
Interest cost	4,453	4,881	8,905	9,762
Expected return on plan assets	(6,270)	(6,237)	(12,540)	(12,474)
Amortization of:
Prior service (credit)/cost	(453)	(456)	(905)	(912)
Actuarial (gain)/loss	2,117	1,363	4,234	2,726
Total net benefit cost	2,608	1,909	5,216	3,817
Nevada Power Company [Member] | United States Postretirement Benefit Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	389	350	778	700
Interest cost	556	602	1,111	1,205
Expected return on plan assets	(631)	(592)	(1,261)	(1,183)
Amortization of:
Prior service (credit)/cost	(23)	229	(46)	458
Actuarial (gain)/loss	289	221	578	441
Total net benefit cost	580	810	1,160	1,621
Sierra Pacific Power Company [Member] | United States Pension Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	1,926	1,695	3,852	3,391
Interest cost	4,558	5,043	9,117	10,086
Expected return on plan assets	(6,162)	(5,937)	(12,324)	(11,875)
Amortization of:
Prior service (credit)/cost	(277)	(277)	(554)	(554)
Actuarial (gain)/loss	2,501	2,026	5,001	4,052
Total net benefit cost	2,546	2,550	5,092	5,100
Sierra Pacific Power Company [Member] | United States Postretirement Benefit Plans of US Entity, Defined Benefit [Member]
Net periodic benefit cost [Abstract]
Service cost	251	227	501	455
Interest cost	1,104	1,283	2,207	2,566
Expected return on plan assets	(1,022)	(941)	(2,043)	(1,882)
Amortization of:
Prior service (credit)/cost	(933)	(1,220)	(1,866)	(2,439)
Actuarial (gain)/loss	592	504	1,185	1,007
Total net benefit cost	$ (8)	$ (147)	$ (16)	$ (293)

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COMMITMENTS AND CONTINGENCIES, Environmental (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Environmental [Abstract]
Regional Haze	$ 77.1
Nevada Power Company [Member]
Environmental [Abstract]
Reclamation estimate of coal washing and load-out facility site	4.0
Nevada Power Company [Member] | Navajo Generating Station [Member]
Environmental [Abstract]
Ownership interest in generating stations (in hundredths)	11.30%
Regional Haze	1,100.0
Sierra Pacific Power Company [Member] | Valmy Generating Station [Member]
Environmental [Abstract]
Ownership interest in generating stations (in hundredths)	50.00%
Mercury Air Toxic Standards Costs	$ 6.4

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LONG-TERM DEBT

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Long-term Debt [Text Block]

NOTE 5.LONG-TERM DEBT

NVE's, NPC's and SPPC's long-term debt consists of the following (dollars in thousands):

						June 30,								December 31,
						2013								2012
Long-Term Debt:			Stated Rate		Maturity Date	Consolidated		NVE Holding Co.		NPC		SPPC		Consolidated		NVE Holding Co.		NPC		SPPC
Secured Debt
	General and Refunding Mortgage Securities
		NPC Series L	5.875	%	2015	$	250,000	$	0	$	250,000	$	0	$	250,000	$	0	$	250,000	$	0
		NPC Series M	5.950	%	2016		210,000		0		210,000		0		210,000		0		210,000		0
		NPC Series N	6.650	%	2036		370,000		0		370,000		0		370,000		0		370,000		0
		NPC Series O	6.500	%	2018		325,000		0		325,000		0		325,000		0		325,000		0
		NPC Series R	6.750	%	2037		350,000		0		350,000		0		350,000		0		350,000		0
		NPC Series S	6.500	%	2018		500,000		0		500,000		0		500,000		0		500,000		0
		NPC Series U	7.375	%	2014		125,000		0		125,000		0		125,000		0		125,000		0
		NPC Series V	7.125	%	2019		500,000		0		500,000		0		500,000		0		500,000		0
		NPC Series X	5.375	%	2040		250,000		0		250,000		0		250,000		0		250,000		0
		NPC Series Y	5.450	%	2041		250,000		0		250,000		0		250,000		0		250,000		0
		SPPC Series M	6.000	%	2016		450,000		0		0		450,000		450,000		0		0		450,000
		SPPC Series P	6.750	%	2037		251,742		0		0		251,742		251,742		0		0		251,742
		SPPC Series Q	5.450	%	2013		250,000		0		0		250,000		250,000		0		0		250,000
	Variable Rate Debt (Secured
	by General and Refunding
	Mortgage Securities)
		NPC IDRB Series 2000A			2020		98,100		0		98,100		0		98,100		0		98,100		0
		NPC PCRB Series 2006			2036		37,700		0		37,700		0		37,700		0		37,700		0
		NPC PCRB Series 2006A			2032		37,975		0		37,975		0		37,975		0		37,975		0
		SPPC PCRB Series 2006A			2031		58,200		0		0		58,200		58,200		0		0		58,200
		SPPC PCRB Series 2006B			2036		75,000		0		0		75,000		75,000		0		0		75,000
		SPPC PCRB Series 2006C			2036		81,475		0		0		81,475		81,475		0		0		81,475
Senior Notes
		NVE Senior Notes	6.250	%	2020		315,000		315,000		-		-		315,000		315,000		-		-
		NVE Term Loan	2.560	%	2014		195,000		195,000		-		-		195,000		195,000		-		-
Obligations under capital leases							42,154		-		40,233		1,921		44,258		-		42,908		1,350
Unamortized bond premium and discount, net							1,405		-		(9,329)		10,734		1,631		-		(9,827)		11,458
Current maturities							(480,018)		-		(229,743)		(250,275)		(356,283)		-		(106,048)		(250,235)
Total Long-Term Debt						$	4,543,733	$	510,000	$	3,104,936	$	928,797	$	4,669,798	$	510,000	$	3,230,808	$	928,990

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

Nevada Power Company

Notice of Redemption

On July 26, 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. NPC intends to redeem the aggregate principal amount outstanding of $98.1 million on August 21, 2013 at 100% of the principal amount plus accrued interest. NPC intends to fund such redemption with the use of cash on hand

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REGULATORY ACTIONS, Summary of Regulatory Actions (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
SPPC Gas [Member] | GRC [Member]
Revenue Requirement Subject To Change:
Effective Date	January 1, 2014
SPPC Electric [Member] | GRC [Member]
Revenue Requirement Subject To Change:
Effective Date	January 1, 2014
Nevada Power Company [Member]
Revenue Requirement Subject To Change:
Requested Revenue Requirement	$ 68.5
Present Revenue Requirement	117.5
$ Change in Revenue Requirement	(49.0)
Nevada Power Company [Member] | REPR [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	28.4	[1]
Present Revenue Requirement	38.7	[1]
$ Change in Revenue Requirement	(10.3)	[1]
Nevada Power Company [Member] | TRED [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	15.7	[1]
Present Revenue Requirement	15.9	[1]
$ Change in Revenue Requirement	(0.2)	[1]
Nevada Power Company [Member] | EEPR Base [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	45.9	[1]
Present Revenue Requirement	32.6	[1]
$ Change in Revenue Requirement	13.3	[1]
Nevada Power Company [Member] | EEPR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	(29.9)	[1]
Present Revenue Requirement	9.0	[1]
$ Change in Revenue Requirement	(38.9)	[1]
Nevada Power Company [Member] | EEIR Base [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013
Requested Revenue Requirement	15.1
Present Revenue Requirement	10.6
$ Change in Revenue Requirement	4.5
Nevada Power Company [Member] | EEIR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013
Requested Revenue Requirement	(6.7)
Present Revenue Requirement	10.7
$ Change in Revenue Requirement	(17.4)
Sierra Pacific Power Company [Member] | SPPC Gas [Member]
Revenue Requirement Subject To Change:
Effective Date	October 2013
$ Change in Revenue Requirement	(0.2)
Sierra Pacific Power Company [Member] | SPPC Electric [Member]
Revenue Requirement Subject To Change:
Requested Revenue Requirement	60.2
Present Revenue Requirement	64.7
$ Change in Revenue Requirement	(4.5)
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | REPR [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	42.3	[1]
Present Revenue Requirement	44.4	[1]
$ Change in Revenue Requirement	(2.1)	[1]
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | TRED [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	7.4	[1]
Present Revenue Requirement	6.3	[1]
$ Change in Revenue Requirement	1.1	[1]
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | EEPR Base [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	6.0	[1]
Present Revenue Requirement	5.6	[1]
$ Change in Revenue Requirement	0.4	[1]
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | EEPR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013	[1]
Requested Revenue Requirement	(2.2)	[1]
Present Revenue Requirement	1.8	[1]
$ Change in Revenue Requirement	(4.0)	[1]
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | EEIR Base [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013
Requested Revenue Requirement	5.6
Present Revenue Requirement	4.7
$ Change in Revenue Requirement	0.9
Sierra Pacific Power Company [Member] | SPPC Electric [Member] | EEIR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date	Oct. 2013
Requested Revenue Requirement	1.1
Present Revenue Requirement	1.9
$ Change in Revenue Requirement	$ (0.8)

[1] Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to therevenues collected. As a result, such programs have no effect on Operating or Net Income.

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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 $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is under contract with a third party regarding the potential purchase of the property, subject to a 180 day due diligence period.

Reid Gardner Generating Station

On October 4, 2011, NPC 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 NPC's Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns units 1-3. Unit 4 of the facility is co-owned with the CDWR. The EPA's Section 114 information request does not allege any incidents of non-compliance at the plant. NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, NPC cannot predict the impact, if any, associated with this information request.

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. At this time, SPPC cannot predict the impact, if any, associated with this information request.

NPC and SPPC

NVision and SB 123

NVision is a comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs.  NVision includes the following significant details:

Accelerating the plan to retire 800 MW of coal plants, starting as soon as December 31, 2014;

Replacement of such coal plants with the construction, acquisition or contracting for, 350 MWs of in state renewable capacity;

Construction or acquisition and ownershipof gas-fired generating plants for 550 MWs;

Implementation of programs to assist customers in reducing peak electric demand; and

Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.

In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative and includesthe requirements as outlined in the bullets above. The Utilities expect to file an IRP in 2014 to specifically address the plan details as outlined above.

Greenhouse Gas/Carbon Regulations

In conjunction with the release of President Obama's Climate Action Plan on June 25, 2013, the President issued a memorandum directing the EPA to take several actions on carbon emissions standards for power plants. As discussed above, NVisionand the passage of SB 123, will yield substantial reductions in carbon as NVE and the Utilities retire their existing coal-fired generating facilities on an accelerated schedule. While the Utilities currently cannot predict the financial impact or final mandates by President Obama's Climate Action Plan or the EPAs final rules, NVE and the Utilities remain committed to taking progressive steps over time to limit the carbon emissions from its generation fleet by retiring older fossil units and replacing them with new, lower emissions and/or zero emission sources.

Regional Haze Rules 

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA's Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. In March 2012, the EPA approved Nevada's SIP as it pertains to all affected units and emissions, except for NOx controls at units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station units 1-3, approving and rejecting certain components of Nevada's SIP.For the limited portions of Nevada's SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada's determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015.On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013,the EPA granted reconsideration of the compliance date for the BART retrofits for units 1, 2 and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015 to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action. The comment period for this action closed on May 30, 2013 and the EPA is expected to finalize its decision by the end of the summer.

NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE has received approval from the PUCN to retire Tracy Generating Station units 1 and 2, and install retrofit controls on Tracy Generating Station unit 3 and Ft. Churchill Generating Station units 1 and 2. As previously disclosed, NVE and the Utilities intend to also file with the PUCN their IRP detailing how they will address the phased retirement of coal fired assets as required under SB 123. While the BART requirements specify the installation of SNCR's on Reid Gardner Generating Station units 1, 2 and 3, the passage of SB 123 could result in the early retirement of those units prior to the required BART installation deadline, pending the final approval of the PUCN. Therefore, in NVE and the Utilities' IRP filing planned for 2014, NVE and the Utilities would need to obtain either the PUCN approval to retire those units as soon as the end of 2014 or seek approval for the BART retrofit installation with an alternate retirement date. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, including Reid Gardner units 1, 2 and 3, but excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities' regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA's final determinations with respect to Nevada's regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA's March 2012 approval of Nevada's SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA's approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA's August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned.

The Navajo Generating Station is also an affected unit under EPA's Regional Haze Rules. On January 17, 2013, the EPAannounced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline forreducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impacton the viability of the plant's future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion inadditional emission controls at the plant of which NPC's ownership share is 11.3%.

The comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested a 90-day extension, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners. In March 2013, the EPA granted a 90-day extension to August 5, 2013. On June 26, 2013, the EPA provided a second extension of the public comment period for the proposed rulemaking on Navajo Generating Station based on a request from Salt River, on behalf of the Navajo Nation, the Gila River Indian Community, the Central Arizona Water Conservation District, the Environmental Defense Fund and the U.S. Department of the Interior.The EPA is extending the comment period an additional 60-days and the public comment period will now close on October 4, 2013.Prior to the close of the public comment period, the EPA has announced it will hold a hearing at one location each on the Navajo Reservation and the Hopi Reservations.

Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear,and EPA's overall proposal will be subject to significant input from a variety of affected parties before it is finalized. NVE cannot predictat this timethe ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take at this time.

Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Registera final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule, requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the Maximum Achievable Control Technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE's generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC's Valmy Generating Station, unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for unit 1, at an estimated capital cost for SPPC's 50% ownership interest of approximately $6.4 million, excluding AFUDC. Note that the actual cost will be dependent upon final engineering design.

The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order to allow for additional testing of various mercury control strategies.  Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo Generating Station units, a cost estimate is unable to be determined at this time.

Currently, all four of the units at the Reid Gardner Generating Station, as well as unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

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. In addition, NVE and the Utilities may also be subject to future state or federal regulations. Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility. If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.

       In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station units 1, 2 and 3 and as co-owners and operating agent of unit 4. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs. However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

       NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

Litigation Contingencies

NVE

Litigation Related to the MidAmerican Merger

Following the announcement of the proposed acquisition of NVE by MEHC through its subsidiary Silver Merger Sub, Inc. on May 29, 2013, several complaints were filed by alleged NVE shareholders in the Eighth Judicial District Court in Clark County, Nevada, challenging the MidAmerican Merger.

On June 6, 2013, a complaint was filed on behalf of a putative class of NVE public shareholders, naming NVE, its BOD, and Silver Merger Sub, Inc., as defendants. This complaint was amended on July 16, 2013. The amended complaint generally alleges that the individual defendants breached their fiduciary duties in connection with the proposed MidAmerican Merger, including by approving the transaction on allegedly unfair terms, at an allegedly unfair price and pursuant to an allegedly inadequate process; allegedly acting with conflicts and in their own personal interests rather than those of shareholders; and making inadequate disclosures in connection with requested shareholder approval of the proposed MidAmerican Merger. The amended complaint also alleges that Silver Merger Sub. Inc., NVE and MEHC aided and abetted the individual defendants in breaching their fiduciary duties.

Three additional complaints were filed on June 7, 2013, June 10, 2013 and July 12, 2013, respectively. These complaints contain claims and allegations similar to the amended July 16, 2013 complaint and seek similar relief on behalf of the same putative class.

The outcome of these lawsuits is uncertain. An adverse judgment could have a material adverse effect on the operations of NVE, including the possibility of delaying or permanently enjoining the MidAmerican Merger. NVE and its BOD intend to vigorously defend the lawsuits.

NPC

Peabody Western Coal Company – Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and 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.

In June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit. In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement amongthe Navajo Nation, Peabody, Salt River and SCE. At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station.

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. NPC has reached a tentative settlement with SCE on this matter. The terms of the settlement will not be material to NPC.

SPPC

Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million. One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. 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. The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam's insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers. The insurers contested the extent and amount of insurance coverage. Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC's right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost. In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

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.

Other Commitments

NPC and SPPC

ON Line TUA

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE's future lease payments are adjusted for final capital costs, for which theUtilities expect to get regulatory recovery. For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of June 30, 2013, capitalized construction costs associated with GBT's 75% interest of $336.1 million and $20.7million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

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REGULATORY ACTIONS

6 Months Ended

Jun. 30, 2013

REGULATORY ACTIONS [Abstract]

REGULATORY ACTIONS

NOTE 4.REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 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 June 30, 2013 (dollars in thousands):

		June 30, 2013
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance as of December 31, 2012	$	(151,880)	$	(101,117)	$	(32,693)	$	(18,070)
	2013 Amortization		94,134		57,887		19,196		17,051
	2013 Deferred Energy Under Collections (1)		75,030		55,625		16,230		3,175
Deferred Energy Balance at June 30, 2013 - Subtotal		$	17,284	$	12,395	$	2,733	$	2,156
Reinstatement of deferred energy (effective 6/07, 10 years)			95,103		95,103		-		-
	Total Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
Current Assets
	Deferred energy	$	31,113	$	27,389	$	2,733	$	991
Non-current Assets
	Deferred energy		81,274		80,109		-		1,165
	Total Net Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
(1)	These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting
	Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Joint Application for the merger between NVE and MEHC (MidAmerican Merger)

In July 2013, NVE and MEHC filed a joint application with the PUCN seeking the authorization of NVE's merger with MEHC. Under Nevada law, the PUCN may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “in the public interest.” If the PUCN does not issue a final order regarding the MidAmerican Merger within 180 days of the application filing date, the transaction will be deemed to be authorized. Based on the date of filing, the expected authorization date for the joint application between NVE and MEHC is January 2014.

Joint Application of NPC and SPPC (One Company Merger Filing)

In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:

Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC's assets and obligations to NPC, and renaming the surviving utility NVEOC;

Authority to transfer SPPC's certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC's CPCN to reflect the name of the surviving utility, NVEOC; and

Authority to transfer all SPPC's electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”Hearings are expected to begin in February 2014.

Financing Application

Concurrent with the One Company Merger filing, NPC and SPPC filed a joint financing application with the PUCN.  The application requested the PUCN to restate and review the Utilities' existing unused authority and to assign and consolidate the unused authority under NVEOC.  In addition, the application requests new authority of $705.0 million.  The consolidated authority would give NVEOC authority to issue new debt of $1.1 billion and authority to refinance or redeem debt of $1.5 billion. The application does not seek a change to NPC's and SPPC's existing revolving credit facility authority of $1.3 billion and $600 million, respectively.   The Utilities have requested that the financing application be consolidated with the One Company Merger filing. However, as the One Company Merger will not be approved prior to the December 31, 2013 expiration of NPC's current financing authority, NPC requests that its current authority be extended, as well as additional authority to refinance debt of $255 million. A hearing has been set for August 2013 to address whether NPC's financing authority should be extended.

Nevada Power Company

        NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIR and EEPR rate elements. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the table above. Hearings are scheduled in mid-August 2013 with anticipated rates effective October 1, 2013. The March 2013 application includes the following changes in revenue requirement (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR(1)		Oct. 2013	$	28.4	$	38.7	$	(10.3)
	TRED(1)		Oct. 2013		15.7		15.9		(0.2)
	EEPR Base(1)		Oct. 2013		45.9		32.6		13.3
	EEPR Amortization(1)		Oct. 2013		(29.9)		9.0		(38.9)
	EEIR Base		Oct. 2013		15.1		10.6		4.5
	EEIR Amortization		Oct. 2013		(6.7)		10.7		(17.4)
		Total Revenue Requirement		$	68.5	$	117.5	$	(49.0)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected. As a result, such programs have no effect on Operating or Net Income.

Sierra Pacific Power Company

SPPC Electric General Rate Case

       In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations. In this GRC, SPPC is requesting the following:

Decrease in general rates by $9.4 million, approximately a 1.4% decrease; and

ROE and ROR of 10.4% and 7.74%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.

SPPC Gas General Rate Case

       In June 2013, SPPC filed a GRC for its gas operations. In this GRC, SPPC is requesting the following:

Increase in general rates by $10.2 million, approximately a 11.4% increase; and

ROE and ROR of 10.35% and 7.72%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.

SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above. Hearings are scheduled in mid-August 2013 with anticipated rates effective October 1, 2013. The March 2013 application includes the following changes in revenue requirement includes the following (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR (1)		Oct. 2013	$	42.3	$	44.4	$	(2.1)
	TRED (1)		Oct. 2013		7.4		6.3		1.1
	EEPR Base (1)		Oct. 2013		6.0		5.6		0.4
	EEPR Amortization (1)		Oct. 2013		(2.2)		1.8		(4.0)
	EEIR Base		Oct. 2013		5.6		4.7		0.9
	EEIR Amortization		Oct. 2013		1.1		1.9		(0.8)
		Total Revenue Requirement		$	60.2	$	64.7	$	(4.5)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected. As a result, such programs have no effect on Operating or Net Income.

SPPC 2013 Nevada Gas DEAA and REPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above. The amounts requested in this filing result in an overall decrease in revenue requirement of $0.2 million, hearings are scheduled in mid-August 2013, with an anticipated effective date of October 2013.

FERC Matters

NPC

NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003. The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million. In December 2012, FERC issued an order which suspended the proposed rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. All rates are currently subject to refund and final approval by the FERC. However, at this time management is unable to determine the final revenue impact of the case.

SPPC

SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. On June 17, 2013, SPPC filed an unopposed settlement agreement resolving all issues with the FERC, which is pending before FERC for approval for rates effective June 1, 2013. The rate changes under the terms of the settlement agreement are expected to result in an overall annual revenue increase of $1.5 million.

NVE, NPC and SPPC

2013 FERC Transmission Rate Case

In May 2013, NPC and SPPC filed an application with the FERC to reset transmission and ancillary service rates effective on the later of January 1, 2014, or the ON Line in-service date.  The rate changes reflect the addition of the ON Line in transmission revenue requirement.  Various interveners filed protests and NPC and SPPC filed a response to those protests on July 16, 2013.  FERC has not ruled on this application.  At this time, management is unable to determine the final revenue impact of the case.

FERC One Company Merger Request

In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization.  In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and the surviving entity will be renamed NVEOC.  Under Section 203 of the Federal Power Act, the FERC may not authorize the Internal Reorganization unless it finds, among other things, that the transaction is “consistent with the public interest”. If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards. NPC and SPPC requested authorization by December 1, 2013 to enable the transaction to be effective on the latter of December 31, 2013, or the ON Line in-service date.  The application is currently pending before FERC for consideration.

FERC MidAmerican Merger Request

On July 12, 2013, an application was filed with the FERC under Section 203 of the Federal Power Act, to approve the MidAmerican Merger.  The MidAmerican Merger is discussed in more detail in Note 2, Merger Related Activities.   Under Section 203 of the Federal Power Act, the FERC may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “consistent with the public interest.” If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards. The application requests authorization of the proposed transaction by December 19, 2013; however, NVE is unable to determine the timing of a decision in the filing.

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Treasury stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Nevada Power Company [Member]	Nevada Power Company [Member] Common Stock [Member]	Nevada Power Company [Member] Additional Paid-in Capital [Member]	Nevada Power Company [Member] Retained Earnings [Member]	Nevada Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Sierra Pacific Power Company [Member]	Sierra Pacific Power Company [Member] Common Stock [Member]	Sierra Pacific Power Company [Member] Additional Paid-in Capital [Member]	Sierra Pacific Power Company [Member] Retained Earnings [Member]	Sierra Pacific Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011	$ 3,406,079	$ 236,000		$ 2,713,736	$ 464,277	$ (7,934)	$ 2,848,977	$ 1	$ 2,308,219	$ 544,874	$ (4,117)	$ 974,542	$ 4	$ 1,111,262	$ (135,340)	$ (1,384)
Balance (in shares) at Dec. 31, 2011		235,999,750						1,000					1,000
Net Income	81,612				81,612		60,981			60,981		31,323			31,323
Change in market value of risk management assets and liabilities	(475)					(475)
Change in compensation retirement benefits liability and amortization	309					309	127				127	85				85
Unrealized net gain/(loss) on investment	0
Dividends Declared	(70,800)				(70,800)		(79,000)			(79,000)		(20,000)			(20,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2012	3,416,725	236,000		2,713,736	475,089	(8,100)	2,831,085	1	2,308,219	526,855	(3,990)	985,950	4	1,111,262	(124,017)	(1,299)
Balance (in shares) at Jun. 30, 2012		235,999,750						1,000					1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Mar. 31, 2012
Net Income	69,439						62,297					12,679
Change in market value of risk management assets and liabilities	(229)
Change in compensation retirement benefits liability and amortization	154						64					43
Unrealized net gain/(loss) on investment	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2012	3,416,725	236,000		2,713,736			2,831,085	1	2,308,219			985,950	4	1,111,262
Balance (in shares) at Jun. 30, 2012		235,999,750						1,000					1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012	3,557,371	236,000	(16,804)	2,712,943	635,303	(10,071)	2,922,318	1	2,308,211	618,612	(4,506)	1,038,736	4	1,111,266	(70,986)	(1,548)
Balance (in shares) at Dec. 31, 2012	235,079,156	235,999,750	(920,594)				1,000	1,000				1,000	1,000
Net Income	84,708				84,708		64,110			64,110		32,680			32,680
Employee Benefits	17,006		14,591	2,415
Dividend Reinvestment and Employee Benefits (in shares)			792,946
Change in market value of risk management assets and liabilities	496					496
Change in compensation retirement benefits liability and amortization	492					492	194				194	117				117
Unrealized net gain/(loss) on investment	(65)					(65)
Dividends Declared	(89,490)				(89,490)		(80,000)			(80,000)		(20,000)			(20,000)
Common stock repurchased	(6,329)		(6,329)
Common stock repurchaed (shares)			(325,178)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2013	3,564,189	236,000	(8,542)	2,715,358	630,521	(9,148)	2,906,622	1	2,308,211	602,722	(4,312)	1,051,533	4	1,111,266	(58,306)	(1,431)
Balance (in shares) at Jun. 30, 2013	235,546,924	235,999,750	(452,826)				1,000	1,000				1,000	1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Mar. 31, 2013
Net Income	63,233						58,665					10,776
Change in market value of risk management assets and liabilities	297
Change in compensation retirement benefits liability and amortization	246						97					58
Unrealized net gain/(loss) on investment	(65)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2013	$ 3,564,189	$ 236,000					$ 2,906,622	$ 1	$ 2,308,211			$ 1,051,533	$ 4	$ 1,111,266
Balance (in shares) at Jun. 30, 2013	235,546,924	235,999,750					1,000	1,000				1,000	1,000

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LONG-TERM DEBT, Debt Instruments (Details) (USD $)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ (1,405)	$ (1,631)
Current maturities	(480,018,000)	(356,283,000)
Total Long-Term Debt	4,543,733,000	4,669,798,000
Secured, General and Refunding Mortgage Securities, NPC Series L [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Stated interest rate (in hundredths)	5.875%
Maturity date	2015
Secured, General and Refunding Mortgage Securities, NPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	210,000	210,000
Stated interest rate (in hundredths)	5.95%
Maturity date	2016
Secured, General and Refunding Mortgage Securities, NPC Series N [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	370,000	370,000
Stated interest rate (in hundredths)	6.65%
Maturity date	2036
Secured, General and Refunding Mortgage Securities, NPC Series O [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	325,000	325,000
Stated interest rate (in hundredths)	6.50%
Maturity date	2018
Secured, General and Refunding Mortgage Securities, NPC Series R [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	350,000	350,000
Stated interest rate (in hundredths)	6.75%
Maturity date	2037
Secured, General and Refunding Mortgage Securities, NPC Series S [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000	500,000
Stated interest rate (in hundredths)	6.50%
Maturity date	2018
Secured, General and Refunding Mortgage Securities, Series U [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	125,000	125,000
Stated interest rate (in hundredths)	7.375%
Maturity date	2014
Secured, General and Refunding Mortgage Securities, Series V [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000	500,000
Stated interest rate (in hundredths)	7.125%
Maturity date	2019
Secured, General and Refunding Mortgage Securities, Series X [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Stated interest rate (in hundredths)	5.375%
Maturity date	2040
Secured, General and Refunding Mortgage Securities, Series Y [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Stated interest rate (in hundredths)	5.45%
Maturity date	2041
Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	450,000	450,000
Stated interest rate (in hundredths)	6.00%
Maturity date	2016
Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	251,742	251,742
Stated interest rate (in hundredths)	6.75%
Maturity date	2037
Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Stated interest rate (in hundredths)	5.45%
Maturity date	2013
Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	98,100	98,100
Maturity date	2020
Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,700	37,700
Maturity date	2036
Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,975	37,975
Maturity date	2032
Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	58,200	58,200
Maturity date	2031
Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	75,000	75,000
Maturity date	2036
Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	81,475	81,475
Maturity date	2036
NVE Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	195,000	195,000
Stated interest rate (in hundredths)	2.56%
Maturity date	2014
NVE Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	315,000	315,000
Stated interest rate (in hundredths)	6.25%
Maturity date	2020
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	42,154	44,258
Parent Company [Member] | NVE Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	195,000	195,000
Parent Company [Member] | NVE Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	315,000	315,000
Nevada Power Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	9,329	9,827
Current maturities	(229,743,000)	(106,048,000)
Total Long-Term Debt	3,104,936,000	3,230,808,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series L [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	210,000	210,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series N [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	370,000	370,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series O [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	325,000	325,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series R [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	350,000	350,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, NPC Series S [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000	500,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, Series U [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	125,000	125,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, Series V [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000	500,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, Series X [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Nevada Power Company [Member] | Secured, General and Refunding Mortgage Securities, Series Y [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Nevada Power Company [Member] | Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	98,100	98,100
Notice Of Redemption	100,000,000
Notice Of Redemption Date	July 2, 2013
Redemption Date	August 21, 2013
Redemption Percentage	100.00%
Nevada Power Company [Member] | Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,700	37,700
Nevada Power Company [Member] | Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,975	37,975
Nevada Power Company [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	40,233	42,908
Sierra Pacific Power Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	(10,734)	(11,458)
Current maturities	(250,275,000)	(250,235,000)
Total Long-Term Debt	928,797,000	928,990,000
Sierra Pacific Power Company [Member] | Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	450,000	450,000
Sierra Pacific Power Company [Member] | Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	251,742	251,742
Sierra Pacific Power Company [Member] | Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000	250,000
Sierra Pacific Power Company [Member] | Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	58,200	58,200
Sierra Pacific Power Company [Member] | Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	75,000	75,000
Sierra Pacific Power Company [Member] | Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	81,475	81,475
Sierra Pacific Power Company [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 1,921	$ 1,350

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., 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 2012 Form 10-K.

       The results of operations and cash flows of NVE, NPC and SPPC for the six months ended June 30, 2013, are not necessarily indicative of the results to be expected for the full year

Variable Interest Entities

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary 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 June 30, 2013, 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.

NewAccountingPronouncementsAndChangesInAccountingPrinciplesAbstract

NewAccountingPronouncementsPolicyPolicyTextBlock

Recent Accounting Standards Update

Derivatives and Hedging (ASC815)

In July 2013, the FASB amended its existing guidance related to hedge accounting. The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR. The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. NVE and the Utilities do not expect this amendment to have a material impact on their financial statements or disclosure requirements.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements. FASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists. As a result, there is diversity in practice in the presentation of unrecognized tax benefits. The objective of the amendment is to eliminate the diversity in practice, requiring the unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions. The amendment will be applied prospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities. NVE and the Utilities are evaluating the potential effects of this amendment and currently do not anticipate that the adoption of this amendment will have a material impact on the presentation of NVE and the Utilities' consolidated financial statements.

Other Comprehensive Income (ASC 220)

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income. In February 2013, the FASB reinstated certain portions of the deferred amendment. The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

Balance Sheet Offsetting Disclosures (ASC 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements. The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have a material impact on the disclosure requirements for NVE and the Utilities.

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RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

6 Months Ended

Jun. 30, 2013

Compensation and Retirement Disclosure [Abstract]

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NOTE 7.RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities. NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location. Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees. A summary of the components of net periodic pension and other postretirement costs, based on a December 31, 2012 measurement date, follows (dollars in thousands):

NVE
	Pension Benefits					Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,132	$	4,406	$	660	$	595
Interest cost		9,303		10,228		1,677		1,905
Expected return on plan assets		(12,708)		(12,447)		(1,687)		(1,563)
Amortization of prior service cost		(720)		(724)		(952)		(987)
Amortization of net loss		4,797		3,473		890		731
Net periodic benefit cost	$	5,804	$	4,936	$	588	$	681
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	10,264	$	8,813	$	1,320	$	1,191
Interest cost		18,607		20,456		3,353		3,810
Expected return on plan assets		(25,416)		(24,894)		(3,373)		(3,126)
Amortization of prior service cost		(1,441)		(1,448)		(1,905)		(1,974)
Amortization of net loss		9,594		6,945		1,781		1,462
Net periodic benefit cost	$	11,608	$	9,872	$	1,176	$	1,363
The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.6% and 34.6%, respectively.

NPC
	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended June 30,				For the Three Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	2,761	$	2,358	$	389	$	350
Interest cost		4,453		4,881		556		602
Expected return on plan assets		(6,270)		(6,237)		(631)		(592)
Amortization of prior service cost		(453)		(456)		(23)		229
Amortization of net loss		2,117		1,363		289		221
Net periodic benefit cost	$	2,608	$	1,909	$	580	$	810
	Pension Benefits				Other Postretirement Benefits
		For the Six Months Ended June 30,				For the Six Months Ended June 30,
		2013		2012		2013		2012
Service cost	$	5,522	$	4,715	$	778	$	700
Interest cost		8,905		9,762		1,111		1,205
Expected return on plan assets		(12,540)		(12,474)		(1,261)		(1,183)
Amortization of prior service cost		(905)		(912)		(46)		458
Amortization of net loss		4,234		2,726		578		441
Net periodic benefit cost	$	5,216	$	3,817	$	1,160	$	1,621
The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.7% and 36.6%, respectively.

SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended June 30,				For the Three Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	1,926	$	1,695	$	251	$	227
Interest cost		4,558		5,043		1,104		1,283
Expected return on plan assets		(6,162)		(5,937)		(1,022)		(941)
Amortization of prior service cost		(277)		(277)		(933)		(1,220)
Amortization of net loss		2,501		2,026		592		504
Net periodic benefit cost	$	2,546	$	2,550	$	(8)	$	(147)
	Pension Benefits				Other Postretirement Benefits
	For the Six Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	3,852	$	3,391	$	501	$	455
Interest cost		9,117		10,086		2,207		2,566
Expected return on plan assets		(12,324)		(11,875)		(2,043)		(1,882)
Amortization of prior service cost		(554)		(554)		(1,866)		(2,439)
Amortization of net loss		5,001		4,052		1,185		1,007
Net periodic benefit cost	$	5,092	$	5,100	$	(16)	$	(293)
The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 35.6% and 34.5%, respectively.

As discussed in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements in the 2012 Form 10-K, NVE offered a voluntary lump sum pension pay out to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE's pension plan in an effort to reduce NVE's future pension obligation. During the six months ended June 30, 2013, NVE paid $21.0 million in lump sum pension pay outs from the pension assets and does not expect any further material amounts due in 2013.

During the six months ended June 30, 2013, NVE made no contributions to either of the plans. At the present time, it is not anticipated that additional funding will be required for either plan in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.

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LONG-TERM DEBT (Tables)

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Schedule of Long-term Debt

						June 30,								December 31,
						2013								2012
Long-Term Debt:			Stated Rate		Maturity Date	Consolidated		NVE Holding Co.		NPC		SPPC		Consolidated		NVE Holding Co.		NPC		SPPC
Secured Debt
	General and Refunding Mortgage Securities
		NPC Series L	5.875	%	2015	$	250,000	$	0	$	250,000	$	0	$	250,000	$	0	$	250,000	$	0
		NPC Series M	5.950	%	2016		210,000		0		210,000		0		210,000		0		210,000		0
		NPC Series N	6.650	%	2036		370,000		0		370,000		0		370,000		0		370,000		0
		NPC Series O	6.500	%	2018		325,000		0		325,000		0		325,000		0		325,000		0
		NPC Series R	6.750	%	2037		350,000		0		350,000		0		350,000		0		350,000		0
		NPC Series S	6.500	%	2018		500,000		0		500,000		0		500,000		0		500,000		0
		NPC Series U	7.375	%	2014		125,000		0		125,000		0		125,000		0		125,000		0
		NPC Series V	7.125	%	2019		500,000		0		500,000		0		500,000		0		500,000		0
		NPC Series X	5.375	%	2040		250,000		0		250,000		0		250,000		0		250,000		0
		NPC Series Y	5.450	%	2041		250,000		0		250,000		0		250,000		0		250,000		0
		SPPC Series M	6.000	%	2016		450,000		0		0		450,000		450,000		0		0		450,000
		SPPC Series P	6.750	%	2037		251,742		0		0		251,742		251,742		0		0		251,742
		SPPC Series Q	5.450	%	2013		250,000		0		0		250,000		250,000		0		0		250,000
	Variable Rate Debt (Secured
	by General and Refunding
	Mortgage Securities)
		NPC IDRB Series 2000A			2020		98,100		0		98,100		0		98,100		0		98,100		0
		NPC PCRB Series 2006			2036		37,700		0		37,700		0		37,700		0		37,700		0
		NPC PCRB Series 2006A			2032		37,975		0		37,975		0		37,975		0		37,975		0
		SPPC PCRB Series 2006A			2031		58,200		0		0		58,200		58,200		0		0		58,200
		SPPC PCRB Series 2006B			2036		75,000		0		0		75,000		75,000		0		0		75,000
		SPPC PCRB Series 2006C			2036		81,475		0		0		81,475		81,475		0		0		81,475
Senior Notes
		NVE Senior Notes	6.250	%	2020		315,000		315,000		-		-		315,000		315,000		-		-
		NVE Term Loan	2.560	%	2014		195,000		195,000		-		-		195,000		195,000		-		-
Obligations under capital leases							42,154		-		40,233		1,921		44,258		-		42,908		1,350
Unamortized bond premium and discount, net							1,405		-		(9,329)		10,734		1,631		-		(9,827)		11,458
Current maturities							(480,018)		-		(229,743)		(250,275)		(356,283)		-		(106,048)		(250,235)
Total Long-Term Debt						$	4,543,733	$	510,000	$	3,104,936	$	928,797	$	4,669,798	$	510,000	$	3,230,808	$	928,990

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SEGMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information

Three Months Ended
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	731,638	$	4	$	537,124	$	194,510	$	174,302	$	20,208
Energy Costs:
	Fuel for power generation		188,979		-		144,246		44,733		44,733		-
	Purchased power		170,861		-		129,396		41,465		41,465		-
	Gas purchased for resale		17,274		-		-		17,274		-		17,274
	Deferred energy		(86,687)		-		(63,748)		(22,939)		(16,963)		(5,976)
Energy efficiency program costs			12,599		-		10,842		1,757		1,757		-
Total Costs		$	303,026	$	-	$	220,736	$	82,290	$	70,992	$	11,298
Gross Margin		$	428,612	$	4	$	316,388	$	112,220	$	103,310	$	8,910
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			106,798		442		70,100		36,256
Maintenance			24,046		-		15,889		8,157
Depreciation and amortization			98,884		-		70,405		28,479
Taxes other than income			15,846		39		9,632		6,175
Operating Income (Loss)		$	169,486	$	(1,642)	$	141,495	$	29,633

Six Months Ended
June 30, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,315,860	$	7	$	908,987	$	406,866	$	346,929	$	59,937
Energy Costs:
	Fuel for power generation		336,227		-		249,777		86,450		86,450		-
	Purchased power		292,171		-		210,804		81,367		81,367		-
	Gas purchased for resale		54,894		-		-		54,894		-		54,894
	Deferred energy		(165,752)		-		(109,103)		(56,649)		(36,298)		(20,351)
Energy efficiency program costs			22,444		-		18,809		3,635		3,635		-
Total Costs		$	539,984	$	-	$	370,287	$	169,697	$	135,154	$	34,543
Gross Margin		$	775,876	$	7	$	538,700	$	237,169	$	211,775	$	25,394
Merger related costs			13,552		1,165		8,867		3,520
Other operating expenses			211,470		1,917		137,492		72,061
Maintenance			48,952		-		33,964		14,988
Depreciation and amortization			194,886		-		139,066		55,820
Taxes other than income			32,322		261		19,591		12,470
Operating Income (Loss)		$	274,694	$	(3,336)	$	199,720	$	78,310

Three Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	740,698	$	4	$	553,143	$	187,551	$	168,007	$	19,544
Energy Costs:
	Fuel for power generation		112,585		-		81,258		31,327		31,327		-
	Purchased power		164,092		-		135,276		28,816		28,816		-
	Gas purchased for resale		9,492		-				9,492		-		9,492
	Deferred energy		10,490		-		5,053		5,437		4,314		1,123
Energy efficiency program costs			24,600		-		21,200		3,400		3,400		-
Total Costs		$	321,259	$	-	$	242,787	$	78,472	$	67,857	$	10,615
Gross Margin		$	419,439	$	4	$	310,356	$	109,079	$	100,150	$	8,929
Other operating expenses			103,371		1,067		68,650		33,654
Maintenance			24,650		-		16,988		7,662
Depreciation and amortization			96,316		-		69,131		27,185
Taxes other than income			14,266		45		8,596		5,625
Operating Income (Loss)		$	180,836	$	(1,108)	$	146,991	$	34,953

Six Months Ended
June 30, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	1,352,118	$	8	$	948,831	$	403,279	$	337,813	$	65,466
Energy Costs:
	Fuel for power generation		229,620		-		161,807		67,813		67,813		-
	Purchased power		281,208		-		216,807		64,401		64,401		-
	Gas purchased for resale		41,109		-		-		41,109		-		41,109
	Deferred Energy		(1,249)		-		7,224		(8,473)		(8,356)		(117)
Energy efficiency program costs			44,025		-		36,974		7,051		7,051		-
Total Costs		$	594,713	$	-	$	422,812	$	171,901	$	130,909	$	40,992
Gross Margin		$	757,405	$	8	$	526,019	$	231,378	$	206,904	$	24,474
Other operating expenses			206,972		1,774		135,112		70,086
Maintenance			57,176		-		40,061		17,115
Depreciation and amortization			187,178		-		134,121		53,057
Taxes other than income			28,775		237		17,050		11,488
Operating Income (Loss)		$	277,304	$	(2,003)	$	199,675	$	79,632

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Document And Entity Information	6 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
Entity Information [Line Items]
Entity Registrant Name	NV Energy, Inc.
Entity Central Index Key	0000741508
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,580,598
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Nevada Power Company [Member]
Entity Information [Line Items]
Entity Registrant Name	Nevada Power Company
Entity Central Index Key	0000071180
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Sierra Pacific Power Company [Member]
Entity Information [Line Items]
Entity Registrant Name	Sierra Pacific Power Company
Entity Central Index Key	0000090144
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013

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REGULATORY ACTIONS (Tables)

6 Months Ended

Jun. 30, 2013

REGULATORY ACTIONS [Abstract]

Summary of Deferred Energy Amounts

		June 30, 2013
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance as of December 31, 2012	$	(151,880)	$	(101,117)	$	(32,693)	$	(18,070)
	2013 Amortization		94,134		57,887		19,196		17,051
	2013 Deferred Energy Under Collections (1)		75,030		55,625		16,230		3,175
Deferred Energy Balance at June 30, 2013 - Subtotal		$	17,284	$	12,395	$	2,733	$	2,156
Reinstatement of deferred energy (effective 6/07, 10 years)			95,103		95,103		-		-
	Total Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
Current Assets
	Deferred energy	$	31,113	$	27,389	$	2,733	$	991
Non-current Assets
	Deferred energy		81,274		80,109		-		1,165
	Total Net Deferred Energy	$	112,387	$	107,498	$	2,733	$	2,156
(1)	These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting
	Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K.

Summary of Rate Filings

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR(1)		Oct. 2013	$	28.4	$	38.7	$	(10.3)
	TRED(1)		Oct. 2013		15.7		15.9		(0.2)
	EEPR Base(1)		Oct. 2013		45.9		32.6		13.3
	EEPR Amortization(1)		Oct. 2013		(29.9)		9.0		(38.9)
	EEIR Base		Oct. 2013		15.1		10.6		4.5
	EEIR Amortization		Oct. 2013		(6.7)		10.7		(17.4)
		Total Revenue Requirement		$	68.5	$	117.5	$	(49.0)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected. As a result, such programs have no effect on Operating or Net Income.

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR (1)		Oct. 2013	$	42.3	$	44.4	$	(2.1)
	TRED (1)		Oct. 2013		7.4		6.3		1.1
	EEPR Base (1)		Oct. 2013		6.0		5.6		0.4
	EEPR Amortization (1)		Oct. 2013		(2.2)		1.8		(4.0)
	EEIR Base		Oct. 2013		5.6		4.7		0.9
	EEIR Amortization		Oct. 2013		1.1		1.9		(0.8)
		Total Revenue Requirement		$	60.2	$	64.7	$	(4.5)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected. As a result, such programs have no effect on Operating or Net Income.