Nevada Power (NVP) 10-Q 7 Nov 13 2013 Q3 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 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	'	235,581,074
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Nevada Power Company	'	'
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	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Sierra Pacific Power Company	'	'
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	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended				9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
OPERATING REVENUES:	'		'		'		'
OPERATING REVENUES	$1,013,151		$1,026,488		$2,329,011		$2,378,606
Operating Expenses	'		'		'		'
Fuel for power generation	217,954		171,316		554,181		400,936
Purchased power	205,970		205,686		498,141		486,894
Gas purchased for resale	7,383		5,382		62,277		46,491
Deferred energy	-55,270		-29,036		-221,022		-30,285
Energy efficiency program costs	16,042		32,584		38,486		76,609
Regulatory Disallowances	17,335		0		17,335		0
Merger related costs	7,857		0		21,409		0
Other operating expenses	106,068		100,108		317,538		307,080
Maintenance	17,176		19,014		66,128		76,190
Depreciation and amortization	96,801		94,512		291,687		281,690
Taxes other than income	14,214		15,682		46,536		44,457
Total Operating Expenses	651,530		615,248		1,692,696		1,690,062
OPERATING INCOME	361,621		411,240		636,315		688,544
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense (net of AFUDC-debt)	-74,438		-73,667		-221,305		-226,162
Interest Income (Expense) on Regulatory Items	-281		-2,024		-1,124		-6,203
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	2,591		2,415		7,730		6,666
Other Nonoperating Income	3,239		8,827		10,872		19,312
Other expense	-3,829		-4,209		-12,116		-11,909
Total Other Income (Expense)	-72,718		-68,658		-215,943		-218,296
Income Before Income Tax Expense	288,903		342,582		420,372		470,248
Income Tax Expense (Benefit)	101,669		119,412		148,430		165,466
NET INCOME	187,234		223,170		271,942		304,782
Other comprehensive income (loss):	'		'		'		'
Change in compensation retirement benefits liability and amortization	246		155		738		464
Change in market value of risk management assets and liabilities	-11		-193		485		-668
Unrealized net gain/(loss) on investment	98		0		33		0
OTHER COMPREHENSIVE INCOME(LOSS)	333		-38		1,256		-204
COMPREHENSIVE INCOME	187,567		223,132		273,198		304,578
Amount per share basic and diluted	'		'		'		'
Net income per share - basic, in dollars per share	$0.79		$0.95		$1.16		$1.29
Net income per share - diluted, in dollars per share	$0.79		$0.94		$1.15		$1.28
Weighted Average Shares of Common Stock Outstanding - basic	235,578,310		235,961,402		235,421,933		235,986,874
Weighted Average Shares of Common Stock Outstanding - diluted	237,605,514	[1]	238,121,732	[1]	237,339,039	[1]	237,850,530	[1]
Dividends Declared Per Share of Common Stock	$0.19		$0.17		$0.57		$0.47
Nevada Power Company	'		'		'		'
OPERATING REVENUES:	'		'		'		'
OPERATING REVENUES	786,142		802,334		1,695,129		1,751,165
Operating Expenses	'		'		'		'
Fuel for power generation	163,127		123,992		412,904		285,799
Purchased power	172,582		171,687		383,386		388,494
Deferred energy	-45,381		-22,685		-154,484		-15,461
Energy efficiency program costs	13,998		28,492		32,807		65,466
Regulatory Disallowances	11,866		0		11,866		0
Merger related costs	5,620		0		14,487		0
Other operating expenses	70,844		65,372		208,336		200,484
Maintenance	11,208		12,533		45,172		52,594
Depreciation and amortization	68,849		66,975		207,915		201,096
Taxes other than income	8,213		9,743		27,804		26,793
Total Operating Expenses	480,926		456,109		1,190,193		1,205,265
OPERATING INCOME	305,216		346,225		504,936		545,900
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense (net of AFUDC-debt)	-52,856		-51,784		-155,758		-158,791
Interest Income (Expense) on Regulatory Items	-194		-1,623		-1,177		-5,488
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	1,959		1,833		6,151		4,823
Other Nonoperating Income	1,948		7,096		5,330		14,197
Other expense	-1,966		-2,823		-6,200		-7,162
Total Other Income (Expense)	-51,109		-47,301		-151,654		-152,421
Income Before Income Tax Expense	254,107		298,924		353,282		393,479
Income Tax Expense (Benefit)	89,665		103,754		124,730		137,328
NET INCOME	164,442		195,170		228,552		256,151
Other comprehensive income (loss):	'		'		'		'
Change in compensation retirement benefits liability and amortization	96		65		290		192
COMPREHENSIVE INCOME	164,538		195,235		228,842		256,343
Sierra Pacific Power Company	'		'		'		'
OPERATING REVENUES:	'		'		'		'
Electric	213,463		212,073		560,392		549,886
Gas	13,543		12,077		73,480		77,543
OPERATING REVENUES	227,006		224,150		633,872		627,429
Operating Expenses	'		'		'		'
Fuel for power generation	54,827		47,324		141,277		115,137
Purchased power	33,388		33,999		114,755		98,400
Gas purchased for resale	7,383		5,382		62,277		46,491
Deferral of energy - electric-net	-7,925		-5,498		-44,223		-13,854
Deferral of energy - gas-net	-1,964		-853		-22,315		-970
Energy efficiency program costs	2,044		4,092		5,679		11,143
Regulatory Disallowances	5,469		0		5,469		0
Merger related costs	2,008		0		5,528		0
Other operating expenses	34,394		34,128		106,455		104,214
Maintenance	5,968		6,481		20,956		23,596
Depreciation and amortization	27,952		27,537		83,772		80,594
Taxes other than income	5,944		5,894		18,414		17,382
Total Operating Expenses	169,488		158,486		498,044		482,133
OPERATING INCOME	57,518		65,664		135,828		145,296
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense (net of AFUDC-debt)	-15,122		-15,298		-46,020		-47,650
Interest Income (Expense) on Regulatory Items	-87		-401		53		-715
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	632		582		1,579		1,843
Other Nonoperating Income	983		1,399		4,641		4,181
Other expense	-982		-998		-3,803		-3,609
Total Other Income (Expense)	-14,576		-14,716		-43,550		-45,950
Income Before Income Tax Expense	42,942		50,948		92,278		99,346
Income Tax Expense (Benefit)	13,691		16,521		30,347		33,596
NET INCOME	29,251		34,427		61,931		65,750
Other comprehensive income (loss):	'		'		'		'
Change in compensation retirement benefits liability and amortization	59		42		176		127
COMPREHENSIVE INCOME	$29,310		$34,469		$62,107		$65,877
[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 September 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
OTHER INCOME (EXPENSE):	'	'	'	'
AFUDC-debt	$1,957	$1,976	$5,770	$5,479
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	-133	-74	-398	-246
Market value of risk management assets and liabilities	-154	91	-261	355
Unrealized net gain/(loss) on investments	-49	0	-18	0
Nevada Power Company	'	'	'	'
OTHER INCOME (EXPENSE):	'	'	'	'
AFUDC-debt	1,520	1,528	4,763	4,021
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]	'	'	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	-52	-33	-156	-103
Sierra Pacific Power Company	'	'	'	'
OTHER INCOME (EXPENSE):	'	'	'	'
AFUDC-debt	437	448	1,007	1,458
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)	($22)	($95)	($68)

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$373,026	$298,271
Accounts receivable less allowance for uncollectible accounts	483,178	373,099
Materials, supplies and fuel, at average cost	121,699	138,337
Deferred energy costs current	82,235	0
Deferred income taxes	120,186	60,592
Other current assets	49,041	40,750
Total Current Assets	1,229,365	911,049
Public Utilities, Property, Plant and Equipment, Net [Abstract]	'	'
Plant in service	12,195,312	12,031,053
Construction work-in-progress	821,430	708,109
Total	13,016,742	12,739,162
Less accumulated provision for depreciation	3,526,824	3,313,188
Public Utilities, Property, Plant and Equipment, Net	9,489,918	9,425,974
Investments and other property, net	65,354	56,660
Other Assets, Noncurrent [Abstract]	'	'
Deferred Energy Costs Non Current	85,055	87,072
Regulatory assets	1,048,204	1,132,768
Regulatory asset for pension plans	270,565	281,195
Other Assets, Noncurrent	76,705	89,418
Total Deferred Charges and Other Assets	1,480,529	1,590,453
Assets	12,265,166	11,984,136
Current Liabilities:	'	'
Current maturities of long-term debt	129,457	356,283
Accounts Payable	316,681	332,245
Accrued expenses	104,781	127,693
Deferred energy	0	136,865
Other current liabilities	88,299	66,221
Total Current Liabilities	639,218	1,019,307
Long-term debt	4,791,809	4,669,798
Commitments and Contingencies	'	'
Deferred Credits and Other Liabilities:	'	'
Deferred income taxes	1,680,896	1,470,973
Deferred investment tax credit	11,623	13,538
Accrued retirement benefits	144,696	162,260
Regulatory liabilities	631,368	550,687
Other deferred credits and liabilities	656,963	540,202
Total Deferred Credits and Other Liabilities	3,125,546	2,737,660
Shareholders' Equity	'	'
Common stock	236,000	236,000
Treasury stock, at cost	-7,898	-16,804
Other paid-in capital	2,716,311	2,712,943
Retained earnings	772,995	635,303
Accumulated other comprehensive loss	-8,815	-10,071
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,708,593	3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	12,265,166	11,984,136
Nevada Power Company	'	'
Current Assets:	'	'
Cash and cash equivalents	255,236	201,202
Accounts receivable less allowance for uncollectible accounts	367,365	248,501
Materials, supplies and fuel, at average cost	70,929	77,675
Deferred energy costs current	68,391	0
Deferred income taxes	80,062	48,590
Other current assets	35,984	28,763
Total Current Assets	877,967	604,731
Public Utilities, Property, Plant and Equipment, Net [Abstract]	'	'
Plant in service	8,459,208	8,363,566
Construction work-in-progress	695,749	567,941
Total	9,154,957	8,931,507
Less accumulated provision for depreciation	2,203,320	2,035,322
Public Utilities, Property, Plant and Equipment, Net	6,951,637	6,896,185
Investments and other property, net	51,114	49,808
Other Assets, Noncurrent [Abstract]	'	'
Deferred Energy Costs Non Current	84,041	87,072
Regulatory assets	746,286	804,013
Regulatory asset for pension plans	131,628	136,682
Other Assets, Noncurrent	58,097	62,654
Total Deferred Charges and Other Assets	1,020,052	1,090,421
Assets	8,900,770	8,641,145
Current Liabilities:	'	'
Current maturities of long-term debt	129,186	106,048
Accounts Payable	202,915	201,193
Accounts Payable, Related Parties, Current	43,800	42,036
Accrued expenses	63,465	86,433
Deferred energy	0	86,102
Other current liabilities	69,479	52,567
Total Current Liabilities	508,845	574,379
Long-term debt	3,103,980	3,230,808
Commitments and Contingencies	'	'
Deferred Credits and Other Liabilities:	'	'
Deferred income taxes	1,257,818	1,101,804
Deferred investment tax credit	3,857	4,688
Accrued retirement benefits	52,429	49,381
Regulatory liabilities	376,136	323,400
Other deferred credits and liabilities	551,545	434,367
Total Deferred Credits and Other Liabilities	2,241,785	1,913,640
Shareholders' Equity	'	'
Common stock	1	1
Other paid-in capital	2,308,211	2,308,211
Retained earnings	742,164	618,612
Accumulated other comprehensive loss	-4,216	-4,506
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,046,160	2,922,318
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	8,900,770	8,641,145
Sierra Pacific Power Company	'	'
Current Assets:	'	'
Cash and cash equivalents	84,128	60,786
Accounts receivable less allowance for uncollectible accounts	115,765	124,464
Materials, supplies and fuel, at average cost	50,770	60,662
Deferred energy costs current	13,844	0
Intercompany income taxes receivable	10,351	10,351
Deferred income taxes	49,748	21,589
Other current assets	12,566	11,633
Total Current Assets	337,172	289,485
Public Utilities, Property, Plant and Equipment, Net [Abstract]	'	'
Plant in service	3,736,104	3,667,487
Construction work-in-progress	125,681	140,168
Total	3,861,785	3,807,655
Less accumulated provision for depreciation	1,323,504	1,277,866
Public Utilities, Property, Plant and Equipment, Net	2,538,281	2,529,789
Investments and other property, net	7,126	6,499
Other Assets, Noncurrent [Abstract]	'	'
Deferred Energy Costs Non Current	1,014	0
Regulatory assets	301,918	328,755
Regulatory asset for pension plans	135,257	140,268
Other Assets, Noncurrent	13,524	21,477
Total Deferred Charges and Other Assets	451,713	490,500
Assets	3,334,292	3,316,273
Current Liabilities:	'	'
Current maturities of long-term debt	271	250,235
Accounts Payable	84,277	106,415
Accounts Payable, Related Parties, Current	21,543	21,534
Accrued expenses	29,909	32,936
Deferred energy	0	50,763
Other current liabilities	18,821	13,655
Total Current Liabilities	154,821	475,538
Long-term debt	1,177,829	928,990
Commitments and Contingencies	'	'
Deferred Credits and Other Liabilities:	'	'
Deferred income taxes	525,694	465,508
Deferred investment tax credit	7,766	8,850
Accrued retirement benefits	75,133	98,676
Regulatory liabilities	255,232	227,287
Other deferred credits and liabilities	76,974	72,688
Total Deferred Credits and Other Liabilities	940,799	873,009
Shareholders' Equity	'	'
Common stock	4	4
Other paid-in capital	1,111,266	1,111,266
Retained earnings	-49,055	-70,986
Accumulated other comprehensive loss	-1,372	-1,548
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,060,843	1,038,736
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$3,334,292	$3,316,273

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Current Assets:	'	'
Allowance for Doubtful Accounts Receivable, Current	$9,643	$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)	235,581,074	235,079,156
Treasury stock (in shares)	418,675	920,594
Nevada Power Company	'	'
Current Assets:	'	'
Allowance for Doubtful Accounts Receivable, Current	8,584	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	'	'
Current Assets:	'	'
Allowance for Doubtful Accounts Receivable, Current	$1,059	$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

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net Income	$271,942	$304,782
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]	'	'
Depreciation, Depletion and Amortization, Nonproduction	291,687	281,690
Deferred Income Taxes and Tax Credits	152,280	187,229
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	-7,730	-6,666
Deferred energy	-218,156	-18,702
Non Cash Regulatory Disallowance	17,335	0
Amortization of other regulatory assets	134,846	114,626
Deferred rate increase	9,241	2,252
Other Noncash Income (Expense)	3,649	-50,012
Changes in certain assets and liabilities:	'	'
Accounts receivable	-101,079	-151,420
Materials, supplies and fuel	16,909	-18,034
Other current assets	-8,292	-10,390
Accounts payable	7,042	22,646
Increase (Decrease) in Pension and Postretirement Obligations	-17,563	-12,946
Other current liabilities	-594	-23,643
Other deferred assets	-3,634	-3,572
Other regulatory assets	-3,276	34,420
Other deferred liabilities	9,099	-8,066
Net Cash from Operating Activities	553,706	644,194
CASH FLOWS USED BY INVESTING ACTIVITIES:	'	'
Additions to utility plant (excluding AFUDC-equity)	-267,798	-387,790
Customer advances for construction	921	-1,508
Contributions in aid of construction	38,714	63,864
Investments and other property - net	-5,144	217
Net Cash Provided by (Used in) Investing Activities	-233,307	-325,217
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of long-term debt	247,245	130,764
Retirement of long-term debt	-354,443	-272,353
Sale of Common Stock	2,133	0
Common stock repurchased	-6,329	-4,509
Dividends paid	-134,250	-110,920
Net Cash from/(used by) Financing Activities	-245,644	-257,018
Net Increase (Decrease) in Cash and Cash Equivalents	74,755	61,959
Beginning Balance in Cash and Cash Equivalents	298,271	145,944
Ending Balance in Cash and Cash Equivalents	373,026	207,903
Cash paid during period for:	'	'
Interest	233,502	237,262
Income taxes	2	151
Noncash Investing and Financing Items [Abstract]	'	'
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	141,214	132,112
Issuance of treasury stock	13,102	0
Nevada Power Company	'	'
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net Income	228,552	256,151
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]	'	'
Depreciation, Depletion and Amortization, Nonproduction	207,915	201,096
Deferred Income Taxes and Tax Credits	126,080	150,289
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	-6,151	-4,823
Deferred energy	-152,534	-7,335
Non Cash Regulatory Disallowance	11,866	0
Amortization of other regulatory assets	75,893	56,012
Deferred rate increase	9,241	2,252
Other Noncash Income (Expense)	-722	-35,553
Changes in certain assets and liabilities:	'	'
Accounts receivable	-118,863	-164,858
Materials, supplies and fuel	7,017	-5,119
Other current assets	-7,222	-3,715
Accounts payable	20,856	53,985
Increase (Decrease) in Pension and Postretirement Obligations	3,048	3,708
Other current liabilities	-5,819	-25,246
Other deferred assets	-1,613	-2,412
Other regulatory assets	26	50,008
Other deferred liabilities	1,613	-10,412
Net Cash from Operating Activities	399,183	514,028
CASH FLOWS USED BY INVESTING ACTIVITIES:	'	'
Additions to utility plant (excluding AFUDC-equity)	-159,063	-232,608
Customer advances for construction	1,035	713
Contributions in aid of construction	20,263	34,274
Investments and other property - net	1,595	193
Net Cash Provided by (Used in) Investing Activities	-136,170	-197,428
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of long-term debt	-261	132,259
Retirement of long-term debt	-103,718	-271,241
Dividends paid	-105,000	-119,000
Net Cash from/(used by) Financing Activities	-208,979	-257,982
Net Increase (Decrease) in Cash and Cash Equivalents	54,034	58,618
Beginning Balance in Cash and Cash Equivalents	201,202	65,887
Ending Balance in Cash and Cash Equivalents	255,236	124,505
Cash paid during period for:	'	'
Interest	174,050	177,459
Income taxes	1	1
Noncash Investing and Financing Items [Abstract]	'	'
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	119,943	111,052
Sierra Pacific Power Company	'	'
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net Income	61,931	65,750
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]	'	'
Depreciation, Depletion and Amortization, Nonproduction	83,772	80,594
Deferred Income Taxes and Tax Credits	32,847	42,809
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	-1,579	-1,843
Deferred energy	-65,622	-11,367
Non Cash Regulatory Disallowance	5,469	0
Amortization of other regulatory assets	58,769	58,484
Other Noncash Income (Expense)	185	-15,532
Changes in certain assets and liabilities:	'	'
Accounts receivable	17,700	13,452
Materials, supplies and fuel	9,892	-12,915
Other current assets	-934	-6,512
Accounts payable	-16,893	-21,002
Increase (Decrease) in Pension and Postretirement Obligations	-23,544	-18,477
Other current liabilities	2,141	-3,522
Other deferred assets	-2,021	-1,160
Other regulatory assets	-3,302	-15,588
Other deferred liabilities	-1,876	-6,282
Net Cash from Operating Activities	156,935	146,889
CASH FLOWS USED BY INVESTING ACTIVITIES:	'	'
Additions to utility plant (excluding AFUDC-equity)	-108,735	-155,182
Customer advances for construction	-114	-2,221
Contributions in aid of construction	18,451	29,590
Investments and other property - net	24	24
Net Cash Provided by (Used in) Investing Activities	-90,374	-127,789
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of long-term debt	247,506	-1,447
Retirement of long-term debt	-250,725	-1,112
Dividends paid	-40,000	-20,000
Net Cash from/(used by) Financing Activities	-43,219	-22,559
Net Increase (Decrease) in Cash and Cash Equivalents	23,342	-3,459
Beginning Balance in Cash and Cash Equivalents	60,786	55,195
Ending Balance in Cash and Cash Equivalents	84,128	51,736
Cash paid during period for:	'	'
Interest	45,554	45,772
Noncash Investing and Financing Items [Abstract]	'	'
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	$21,271	$21,060

CONSOLIDATED_STATEMENTS_OF_COM2

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $)

Total

Common Stock

Treasury stock

Additional Paid-in Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Nevada Power Company

Nevada Power Company

Nevada Power Company

Nevada Power Company

Nevada Power Company

Sierra Pacific Power Company

Sierra Pacific Power Company

Sierra Pacific Power Company

Sierra Pacific Power Company

Sierra Pacific Power Company

In Thousands, except Share data

Common Stock

Additional Paid-in Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Common Stock

Additional Paid-in Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011

$3,406,079

$236,000

$0

$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

0

'

'

'

'

1,000

'

'

'

'

1,000

'

'

'

Net Income

304,782

'

'

'

304,782

'

256,151

'

'

256,151

'

65,750

'

'

65,750

'

Change in compensation retirement benefits liability and amortization

464

'

'

'

'

464

192

'

'

'

192

127

'

'

'

127

Change in market value of risk management assets and liabilities

-668

'

'

'

'

-668

'

'

'

'

'

'

'

'

'

'

Unrealized net gain/(loss) on investment

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock repurchased

-4,509

'

-4,509

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock repurchased (shares)

'

'

-252,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends Declared

-110,920

'

'

'

-110,920

'

-119,000

'

'

-119,000

'

-20,000

'

'

-20,000

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2012

3,595,228

236,000

-4,509

2,713,736

658,139

-8,138

2,986,320

1

2,308,219

682,025

-3,925

1,020,419

4

1,111,262

-89,590

-1,257

Balance (in shares) at Sep. 30, 2012

'

235,999,750

-252,000

'

'

'

'

1,000

'

'

'

'

1,000

'

'

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

223,170

'

'

'

'

'

195,170

'

'

'

'

34,427

'

'

'

'

Change in compensation retirement benefits liability and amortization

155

'

'

'

'

'

65

'

'

'

'

42

'

'

'

'

Change in market value of risk management assets and liabilities

-193

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrealized net gain/(loss) on investment

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2012

3,595,228

236,000

'

2,713,736

'

'

2,986,320

1

2,308,219

'

'

1,020,419

4

1,111,262

'

'

Balance (in shares) at Sep. 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

271,942

'

'

'

271,942

'

228,552

'

'

228,552

'

61,931

'

'

61,931

'

Employee Benefits

18,603

'

15,235

3,368

'

'

'

'

'

'

'

'

'

'

'

'

Dividend Reinvestment and Employee Benefits (in shares)

'

'

827,097

'

'

'

'

'

'

'

'

'

'

'

'

'

Change in compensation retirement benefits liability and amortization

738

'

'

'

'

738

290

'

'

'

290

176

'

'

'

176

Change in market value of risk management assets and liabilities

485

'

'

'

'

485

'

'

'

'

'

'

'

'

'

'

Unrealized net gain/(loss) on investment

33

'

'

'

'

33

'

'

'

'

'

'

'

'

'

'

Common stock repurchased

-6,329

'

-6,329

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock repurchased (shares)

'

'

-325,178

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends Declared

-134,250

'

'

'

-134,250

'

-105,000

'

'

-105,000

'

-40,000

'

'

-40,000

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2013

3,708,593

236,000

-7,898

2,716,311

772,995

-8,815

3,046,160

1

2,308,211

742,164

-4,216

1,060,843

4

1,111,266

-49,055

-1,372

Balance (in shares) at Sep. 30, 2013

235,581,074

235,999,750

-418,675

'

'

'

1,000

1,000

'

'

'

1,000

1,000

'

'

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

187,234

'

'

'

'

'

164,442

'

'

'

'

29,251

'

'

'

'

Change in compensation retirement benefits liability and amortization

246

'

'

'

'

'

96

'

'

'

'

59

'

'

'

'

Change in market value of risk management assets and liabilities

-11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrealized net gain/(loss) on investment

98

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2013

$3,708,593

$236,000

'

'

'

'

$3,046,160

$1

$2,308,211

'

'

$1,060,843

$4

$1,111,266

'

'

Balance (in shares) at Sep. 30, 2013

235,581,074

235,999,750

'

'

'

'

1,000

1,000

'

'

'

1,000

1,000

'

'

'

CONSOLIDATED_STATEMENTS_OF_COM3

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	($133)	($74)	($398)	($246)
Market value of risk management assets and liabilities	-154	91	-261	355
Unrealized net gain/(loss) on investments	-49	0	-18	0
Nevada Power Company	'	'	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	-52	-33	-156	-103
Sierra Pacific Power Company	'	'	'	'
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	($32)	($22)	($95)	($68)

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	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 nine months ended September 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 September 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 (ASC 815)
	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.    The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.
	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.  ASC 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 can be applied prospectively or retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities have elected to early adopt this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.
	Federal Income Tax Regulations
	In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014.  NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.
	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 an 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 an impact on the disclosure requirements for NVE and the Utilities.

MERGER_RELATED_ACTIVITIES

MERGER RELATED ACTIVITIES	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
MERGER RELATED ACTIVITIES	'
	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.  Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.  The closing is expected to occur in late 2013 or 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 Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVE’s stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied;
	•	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 and 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 nine month periods ending September 30, 2013, NVE incurred $7.9 million (pre-tax) and $21.4 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 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 to 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 5.51% 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 were 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. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit 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.

SEGMENT_INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
SEGMENT INFORMATION	'
	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 costs, energy efficiency program costs and regulatory disallowances 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
	September 30, 2013
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	1,013,151		$	3		$	786,142		$	227,006		$	213,463		$	13,543
	Energy Costs:
	Fuel for power generation	217,954			—			163,127			54,827			54,827			—
	Purchased power	205,970			—			172,582			33,388			33,388			—
	Gas purchased for resale	7,383			—			—			7,383			—			7,383
	Deferred energy	(55,270		)	—			(45,381		)	(9,889		)	(7,925		)	(1,964		)
	Energy efficiency program costs	16,042			—			13,998			2,044			2,044			—
	Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
	Total Costs	$	409,414		$	—		$	316,192		$	93,222		$	87,803		$	5,419
	Gross Margin	$	603,737		$	3		$	469,950		$	133,784		$	125,660		$	8,124
	Merger-related costs	7,857			229			5,620			2,008
	Other operating expenses	106,068			830			70,844			34,394
	Maintenance	17,176			—			11,208			5,968
	Depreciation and amortization	96,801			—			68,849			27,952
	Taxes other than income	14,214			57			8,213			5,944
	Operating Income (Loss)	$	361,621		$	(1,113	)	$	305,216		$	57,518
	Nine Months Ended
	September 30, 2013
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	2,329,011		$	10		$	1,695,129		$	633,872		$	560,392		$	73,480
	Energy Costs:
	Fuel for power generation	554,181			—			412,904			141,277			141,277			—
	Purchased power	498,141			—			383,386			114,755			114,755			—
	Gas purchased for resale	62,277			—			—			62,277			—			62,277
	Deferred energy	(221,022		)	—			(154,484		)	(66,538		)	(44,223		)	(22,315		)
	Energy efficiency program costs	38,486			—			32,807			5,679			5,679			—
	Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
	Total Costs	$	949,398		$	—		$	686,479		$	262,919		$	222,957		$	39,962
	Gross Margin	$	1,379,613		$	10		$	1,008,650		$	370,953		$	337,435		$	33,518
	Merger-related costs	21,409			1,394			14,487			5,528
	Other operating expenses	317,538			2,747			208,336			106,455
	Maintenance	66,128			—			45,172			20,956
	Depreciation and amortization	291,687			—			207,915			83,772
	Taxes other than income	46,536			318			27,804			18,414
	Operating Income (Loss)	$	636,315		$	(4,449	)	$	504,936		$	135,828
	Three Months Ended
	September 30, 2012
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	1,026,488		$	4		$	802,334		$	224,150		$	212,073		$	12,077
	Energy Costs:
	Fuel for power generation	171,316			—			123,992			47,324			47,324			—
	Purchased power	205,686			—			171,687			33,999			33,999			—
	Gas purchased for resale	5,382			—			—			5,382			—			5,382
	Deferred energy	(29,036		)	—			(22,685		)	(6,351		)	(5,498		)	(853		)
	Energy efficiency program costs	32,584			—			28,492			4,092			4,092			—
	Total Costs	$	385,932		$	—		$	301,486		$	84,446		$	79,917		$	4,529
	Gross Margin	$	640,556		$	4		$	500,848		$	139,704		$	132,156		$	7,548
	Other operating expenses	100,108			608			65,372			34,128
	Maintenance	19,014			—			12,533			6,481
	Depreciation and amortization	94,512			—			66,975			27,537
	Taxes other than income	15,682			45			9,743			5,894
	Operating Income (Loss)	$	411,240		$	(649	)	$	346,225		$	65,664
	Nine Months Ended
September 30, 2012
	NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
	Consolidated
Operating Revenues	$	2,378,606		$	12		$	1,751,165		$	627,429		$	549,886		$	77,543
Energy Costs:
Fuel for power generation	400,936			—			285,799			115,137			115,137			—
Purchased power	486,894			—			388,494			98,400			98,400			—
Gas purchased for resale	46,491			—			—			46,491			—			46,491
Deferred Energy	(30,285		)	—			(15,461		)	(14,824		)	(13,854		)	(970		)
Energy efficiency program costs	76,609			—			65,466			11,143			11,143			—
Total Costs	$	980,645		$	—		$	724,298		$	256,347		$	210,826		$	45,521
Gross Margin	$	1,397,961		$	12		$	1,026,867		$	371,082		$	339,060		$	32,022
Other operating expenses	307,080			2,382			200,484			104,214
Maintenance	76,190			—			52,594			23,596
Depreciation and amortization	281,690			—			201,096			80,594
Taxes other than income	44,457			282			26,793			17,382
Operating Income (Loss)	$	688,544		$	(2,652	)	$	545,900		$	145,296

REGULATORY_ACTIONS

REGULATORY ACTIONS	9 Months Ended
	Sep. 30, 2013
REGULATORY ACTIONS [Abstract]	'
REGULATORY ACTIONS	'
	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 September 30, 2013 (dollars in thousands):
		September 30, 2013
		NVE Total				NPC Electric				SPPC Electric				SPPC Gas
	Deferred Energy
	Cumulative Deferred Balance authorized in 2013 DEAA	$	(152,990	)		$	(102,227	)		$	(32,693	)		$	(18,070	)
	2013 Amortization	111,977				69,288				23,695				18,994
	2013 Deferred Energy Under Collections (1)	118,397				95,465				19,697				3,235
	Deferred Energy Balance at September 30, 2013 - Subtotal	$	77,384			$	62,526			$	10,699			$	4,159
	Reinstatement of deferred energy (effective 6/07, 10 years)	89,906				89,906				—				—
	Total Deferred Energy	$	167,290			$	152,432			$	10,699			$	4,159
	Current Assets
	Deferred energy	$	82,235			$	68,391			$	10,322			$	3,522
	Non-current Assets
	Deferred energy	85,055				84,041				377				637
	Total Net Deferred Energy	$	167,290			$	152,432			$	10,699			$	4,159
	(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 the 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 the MidAmerican Merger. 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.  Hearings are scheduled for November 2013.
	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.”  The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 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 requested that its current authority be extended, as well as additional authority to refinance debt of $255 million.  In September 2013, the PUCN accepted a stipulation extending NPC’s existing financing authority until an order is issued in the One Company Merger filing.
	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.  In September 2013, the PUCN issued an order disallowing approximately $1.1 million (pre-tax) in deferred energy costs, which NPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, the PUCN indicated in their order that EEIR revenue should not contribute to the Utilities earning more than their authorized ROR. As NPC earned in excess of its authorized ROR in 2012, the PUCN disallowed approximately $10.8 million in pre-tax EEIR revenues (including carrying charges) which was expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013. Furthermore, as a result of this order and NPC’s estimated 2013 ROR calculated to be in excess of its authorized ROR, NPC has recorded a provision for refund of $11.2 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):
		Effective		Authorized				Present				$ Change in
		Date		Revenue				Revenue				Revenue
				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				(38.9		)
	EEIR Base (2)	Oct. 2013		15.1				10.6				4.5
	EEIR Amortization (3)	Oct. 2013		(17.2		)		10.7				(27.9		)
	Total Revenue Requirement			$	58			$	117.5			$	(59.5	)
	(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.
	(2)	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.
	(3)	Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.
	Sierra Pacific Power Company
	SPPC Electric General Rate Case
	In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:
	•	Decrease in general rates by $4.7 million, approximately a 0.7% 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 and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:
	•	Increase in general rates by $6.0 million, approximately a 6.1% 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. In September 2013, the PUCN issued an order disallowing approximately $0.1 million (pre-tax) in deferred energy costs, which SPPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, with respect to the EEIR disallowance discussed above under NPC, the PUCN disallowed $5.5 million (pre-tax) of SPPC's 2012 EEIR revenues, (including carrying charges) as a result of earning in excess of its authorized ROR. As a result $5.5 million was expensed as a regulatory disallowance for the three and nine months ended September 30, 2013. Also, similar to NPC, SPPC’s estimated 2013 ROR is calculated to be in excess of its authorized ROR, as such, SPPC has recorded a provision for refund of $4.0 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):
		Effective		Authorized				Present				$ Change in
		Date		Revenue				Revenue				Revenue
				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				5.6				0.4
EEPR Amortization (1)	Oct. 2013		(2.1		)		1.8				(3.9		)
EEIR Base (2)	Oct. 2013		5.5				4.7				0.8
EEIR Amortization (3)	Oct. 2013		(3.7		)		1.9				(5.6		)
Total Revenue Requirement			$	55.4			$	64.7			$	(9.3	)
-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.
-2	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.
-3	Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.
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.  In September 2013, the PUCN issued an order resulting in an overall decrease in revenue requirement of $0.2 million.
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.  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, for approval for rates effective June 1, 2013.    FERC approved the settlement on August 29, 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 the transmission revenue requirement.  Various intervenors filed protests and NPC and SPPC filed a response to those protests on July 16, 2013.  On August 5, 2013, FERC issued an order which suspended the rate changes until January 1, 2014 or the in-service date for ON Line, subject to refund. On August 12, 2013 the FERC designated a Settlement Judge and the matter is now in settlement proceedings.  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.  On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains 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.

LONGTERM_DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Long-term Debt	'
	LONG-TERM DEBT
	NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands):
					September 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	5.95	%	2016	210,000			—		210,000			—			210,000			—		210,000			—
	NPC Series N	6.65	%	2036	370,000			—		370,000			—			370,000			—		370,000			—
	NPC Series O	6.5	%	2018	325,000			—		325,000			—			325,000			—		325,000			—
	NPC Series R	6.75	%	2037	350,000			—		350,000			—			350,000			—		350,000			—
	NPC Series S	6.5	%	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	5.45	%	2041	250,000			—		250,000			—			250,000			—		250,000			—
	SPPC Series M	6	%	2016	450,000			—		—			450,000			450,000			—		—			450,000
	SPPC Series P	6.75	%	2037	251,742			—		—			251,742			251,742			—		—			251,742
	SPPC Series Q	5.45	%	2013	—			—		—			—			250,000			—		—			250,000
	SPPC Series T	3.375	%	2023	250,000			—		—			250,000			—			—		—			—
	Variable Rate Debt (Secured by General and Refunding Mortgage Securities)
	NPC IDRB Series 2000A			2020	—			—		—			—			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	6.25	%	2020	315,000			315,000		—			—			315,000			315,000		—			—
	NVE Term Loan	2.56	%	2014	195,000			195,000		—			—			195,000			195,000		—			—
	Obligations under capital leases				38,415			—		36,571			1,844			44,258			—		42,908			1,350
	Unamortized bond premium and discount (net)				759			—		(9,080		)	9,839			1,631			—		(9,827		)	11,458
	Current maturities				(129,457		)	—		(129,186		)	(271		)	(356,283		)	—		(106,048		)	(250,235		)
	Total Long-Term Debt				$	4,791,809		$	510,000	$	3,103,980		$	1,177,829		$	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 Securities are issued.
	Financing Transactions
	Nevada Power Company
	In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
	Sierra Pacific Power Company
	In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.

FAIR_VALUE_OF_FINANCIAL_INSTRU

FAIR VALUE OF FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Disclosures	'
	FAIR VALUE OF FINANCIAL INSTRUMENTS
	The September 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 Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.
	The total fair value of NVE’s consolidated long-term debt at September 30, 2013, is estimated to be $5.6 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 September 30, 2013, is estimated to be $3.7 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 September 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.

RETIREMENT_PLAN_AND_POSTRETIRE

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS	9 Months Ended
	Sep. 30, 2013
Compensation and Retirement Disclosure [Abstract]	'
RETIREMENT PLAN AND POST-RETIREMENT BENEFITS	'
	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 post-retirement 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 post-retirement 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 post-retirement costs for the three and nine months ended September 30 follows. This summary is based on a December 31, measurement date (dollars in thousands):
	NVE
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	15,396		$	13,220		$	1,980		$	1,787
	Interest cost	27,911			30,684			5,030			5,715
	Expected return on plan assets	(38,124		)	(37,341		)	(5,060		)	(4,690		)
	Amortization of prior service cost	(2,162		)	(2,173		)	(2,857		)	(2,961		)
	Amortization of net loss	14,391			10,418			2,671			2,193
	Net periodic benefit cost	$	17,412		$	14,808		$	1,764		$	2,044
	The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.5% and 35.0% respectively.
	NPC
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	8,283		$	7,072		$	1,167		$	1,050
	Interest cost	13,358			14,643			1,667			1,807
	Expected return on plan assets	(18,810		)	(18,711		)	(1,892		)	(1,775		)
	Amortization of prior service cost	(1,358		)	(1,367		)	(69		)	687
	Amortization of net loss	6,351			4,089			867			662
	Net periodic benefit cost	$	7,824		$	5,726		$	1,740		$	2,431
	The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.9% and 36.9% respectively.
	SPPC
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	5,778		$	5,086		$	752		$	682
	Interest cost	13,676			15,130			3,310			3,848
	Expected return on plan assets	(18,486		)	(17,813		)	(3,065		)	(2,823		)
	Amortization of prior service cost	(831		)	(831		)	(2,798		)	(3,658		)
	Amortization of net loss	7,502			6,078			1,777			1,511
	Net periodic benefit cost	$	7,639		$	7,650		$	(24	)	$	(440	)
	The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.
	As discussed in Note 10, Retirement Plan and Post-Retirement 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 nine months ended September 30, 2013, NVE paid $21.5 million in lump sum pension pay outs from the pension assets. The company does not expect any further material amounts to be paid in 2013.
During the nine months ended September 30, 2013 and 2012, the company made contributions to the pension plan in the amount of $20.0 million and $15.0 million, respectively and $5.0 million and $7.1 million, respectively in contributions to the other post-retirement benefits plan. 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.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	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.  The site is under contract for sale to a third party and the sale is expected to close in the fourth quarter of 2013.   The sale will not be material to NPC.
	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 1-4, with the interest of CDWR in Unit 4 having been terminated in October 2013.  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 other electric generating plants.  NVision includes the following significant details:
	•	Accelerating the plan to retire 800 MWs of coal plants, starting as soon as December 31, 2014;
	•	Replacement of such coal plants with the procurement of 300 MWs from renewable facilities;
	•	Construction or acquisition and ownership of 50 MWs of electric generating capacity from renewable facilities;
	•	Construction or acquisition and ownership of 550 MWs of electric generating capacity from other electric generating plants; 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 includes the requirements as outlined in the bullets above.  The Utilities, along with other interested parties, are currently working with the PUCN to finalize the rulemaking associated with this bill and expect to file an emissions reduction plan 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 EPA’s 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 and t he comment period for this action closed on May 30, 2013. In August 2013, the EPA announced it was taking final action to extend the date by which Units 1, 2, and 3 at Reid Gardner Generating Station must meet the BART limits to reduce emissions of nitrogen oxides. The final date is now affirmed as June 30, 2016.
	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 file with the PUCN their emissions reduction plan in 2014 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 2014, NVE and the Utilities will file an emissions reduction plan. 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 Generating Station 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 EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impact on 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 in additional emission controls at the plant of which NPC’s ownership share is 11.3%.
	The original comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested and was granted several extensions, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners.
	On September 25, 2013, the EPA issued a supplemental proposal which included a BART alternative called the Technical Work Group (“TWG”) Alternative. The TWG Alternative is based upon the proposal submitted to the EPA in July 2013 by a group of Navajo Generating Station stakeholders called the TWG. At this time, the EPA is concurrently accepting comments on the BART determination and the EPA Alternative which were proposed in February 2013, as well the TWG Alternative proposed in the supplemental proposal. Comments are now due by January 6, 2014.
	Given the uncertainties that remain regarding the various lease and agreement renewal terms, the timeline for BART installation, and the fact that the EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take. As a result of the passage of NVision and these uncertainties, NPC expects to file in 2014 an emissions reduction plan to specifically address its ownership participation in the Navajo Generating Station.
	Mercury and Air Toxics Standards (MATS)
	In December 2011, the EPA signed for publication in the Federal Register a 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-owner and operating agent of Unit 4.  In October 2013, NPC purchased Unit 4 from CDWR. 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.
	Four additional complaints were filed in the Eighth Judicial District Court in Clark County, Nevada on June 7, 2013, June 10, 2013, July 12, 2013 and August 16, 2013.  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. One complaint was voluntarily dismissed. The remaining cases were consolidated in Department XI of the Eighth Judicial District Court in Clark County, Nevada.
	An agreement-in-principle has been reached between the parties to these lawsuits, which was memorialized in a memorandum of understanding executed on September 4, 2013.  The memorandum of understanding called for NVE to supplement the proxy statement for the special meeting of stockholders related to the MidAmerican Merger, and the supplemental information was in fact provided via NVE’s Form 8-K dated September 9, 2013. The parties currently are preparing a final stipulation of settlement which will be submitted to the court for approval. It is not known at this time when the court will set hearings and/or issue a final order, but NVE does not expect the outcome of this litigation or settlement to delay the closing of the MidAmerican Merger or otherwise have a material impact on NVE.
	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 among the 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.  In October 2013, NPC settled with SCE on this matter.  The terms of the settlement are not material to NPC.
	November 2005 Land Investors
	In 2006, November 2005 Land Investors, LLC (“NLI”) purchased from the U.S. through the Bureau of Land Management (“BLM”) 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land was and is traversed by a 500kV transmission line owned by NPC and sited pursuant to a pre-existing right-of-way grant (“Grant”) from the BLM. Subsequent to NLI’s purchase, a dispute arose as to whether NPC owed rent and, if it did, the amount owed to NLI under the Grant. NLI eventually “terminated” the Grant and brought claims against NPC for breach of contract, inverse condemnation and trespass. NPC counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada. In September 2013, the court awarded NLI approximately $1.0 million for unpaid rent and $5.1 million for inverse condemnation, plus interest and attorneys’ fees. The court also found NPC was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor.
	NPC has appealed to the Nevada Supreme Court, which has yet to establish a schedule for the appeal. Management cannot assess or predict the outcome of the case at this time, but it is not expected to 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 years time to rebuild to start at the conclusion of all litigation.
	The District Court has now set the briefing schedule 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 the Utilities 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 September 30, 2013, capitalized construction costs associated with GBT’s 75% interest of $370.8 million and $19.4 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

EARNINGS_PER_SHARE_NVE

EARNINGS PER SHARE (NVE)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	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 September 30,				Nine Months Ended September 30,
		2013		2012		2013		2012
	Basic EPS
	Numerator ($000)
	Net Income	$	187,234	$	223,170	$	271,942	$	304,782
	Denominator
	Weighted average number of common shares outstanding	235,578,310		235,961,402		235,421,933		235,986,874
	Per Share Amounts
	Net Income per share - basic	$	0.79	$	0.95	$	1.16	$	1.29
	Diluted EPS
	Numerator ($000)
	Net Income	$	187,234	$	223,170	$	271,942	$	304,782
	Denominator(1)
	Weighted average number of shares outstanding before dilution	235,578,310		235,961,402		235,421,933		235,986,874
	Stock options	61,927		39,256		46,537		37,592
	Non-Employee Director stock plan	190,705		166,829		185,337		160,257
	Employee stock purchase plan	4,149		6,742		5,831		6,785
	Restricted Shares	412,000		584,750		487,667		533,750
	Performance Shares	1,358,423		1,362,753		1,191,734		1,125,272
	Diluted Weighted Average Number of Shares	237,605,514		238,121,732		237,339,039		237,850,530
	Per Share Amounts
	Net income per share - diluted	$	0.79	$	0.94	$	1.15	$	1.28
	-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 September 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

COMMON_STOCK_AND_OTHER_PAIDIN_

COMMON STOCK AND OTHER PAID-IN CAPITAL	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
COMMON STOCK AND OTHER PAID-IN CAPITAL	'
	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
	November 6, 2013	$0.19	December 18, 2013	December 3, 2013
	On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of $105.0 million and $40.0 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 nine months ended September 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million.  During the nine months ended September 30, 2013, NVE re-issued 827,097 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.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 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 nine months ended September 30, 2013, are not necessarily indicative of the results to be expected for the full year.
Variable Interest Entities	'
	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 September 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.
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements	'
	Recent Accounting Standards Update
	Derivatives and Hedging (ASC 815)
	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.    The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.
	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.  ASC 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 can be applied prospectively or retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities have elected to early adopt this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.
	Federal Income Tax Regulations
	In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014.  NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.
	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 an 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 an impact on the disclosure requirements for NVE and the Utilities.

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information	'
	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
	September 30, 2013
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	1,013,151		$	3		$	786,142		$	227,006		$	213,463		$	13,543
	Energy Costs:
	Fuel for power generation	217,954			—			163,127			54,827			54,827			—
	Purchased power	205,970			—			172,582			33,388			33,388			—
	Gas purchased for resale	7,383			—			—			7,383			—			7,383
	Deferred energy	(55,270		)	—			(45,381		)	(9,889		)	(7,925		)	(1,964		)
	Energy efficiency program costs	16,042			—			13,998			2,044			2,044			—
	Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
	Total Costs	$	409,414		$	—		$	316,192		$	93,222		$	87,803		$	5,419
	Gross Margin	$	603,737		$	3		$	469,950		$	133,784		$	125,660		$	8,124
	Merger-related costs	7,857			229			5,620			2,008
	Other operating expenses	106,068			830			70,844			34,394
	Maintenance	17,176			—			11,208			5,968
	Depreciation and amortization	96,801			—			68,849			27,952
	Taxes other than income	14,214			57			8,213			5,944
	Operating Income (Loss)	$	361,621		$	(1,113	)	$	305,216		$	57,518
	Nine Months Ended
	September 30, 2013
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	2,329,011		$	10		$	1,695,129		$	633,872		$	560,392		$	73,480
	Energy Costs:
	Fuel for power generation	554,181			—			412,904			141,277			141,277			—
	Purchased power	498,141			—			383,386			114,755			114,755			—
	Gas purchased for resale	62,277			—			—			62,277			—			62,277
	Deferred energy	(221,022		)	—			(154,484		)	(66,538		)	(44,223		)	(22,315		)
	Energy efficiency program costs	38,486			—			32,807			5,679			5,679			—
	Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
	Total Costs	$	949,398		$	—		$	686,479		$	262,919		$	222,957		$	39,962
	Gross Margin	$	1,379,613		$	10		$	1,008,650		$	370,953		$	337,435		$	33,518
	Merger-related costs	21,409			1,394			14,487			5,528
	Other operating expenses	317,538			2,747			208,336			106,455
	Maintenance	66,128			—			45,172			20,956
	Depreciation and amortization	291,687			—			207,915			83,772
	Taxes other than income	46,536			318			27,804			18,414
	Operating Income (Loss)	$	636,315		$	(4,449	)	$	504,936		$	135,828
	Three Months Ended
	September 30, 2012
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
	Operating Revenues	$	1,026,488		$	4		$	802,334		$	224,150		$	212,073		$	12,077
	Energy Costs:
	Fuel for power generation	171,316			—			123,992			47,324			47,324			—
	Purchased power	205,686			—			171,687			33,999			33,999			—
	Gas purchased for resale	5,382			—			—			5,382			—			5,382
	Deferred energy	(29,036		)	—			(22,685		)	(6,351		)	(5,498		)	(853		)
	Energy efficiency program costs	32,584			—			28,492			4,092			4,092			—
	Total Costs	$	385,932		$	—		$	301,486		$	84,446		$	79,917		$	4,529
	Gross Margin	$	640,556		$	4		$	500,848		$	139,704		$	132,156		$	7,548
	Other operating expenses	100,108			608			65,372			34,128
	Maintenance	19,014			—			12,533			6,481
	Depreciation and amortization	94,512			—			66,975			27,537
	Taxes other than income	15,682			45			9,743			5,894
	Operating Income (Loss)	$	411,240		$	(649	)	$	346,225		$	65,664
	Nine Months Ended
	September 30, 2012
		NVE			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
		Consolidated
Operating Revenues	$	2,378,606		$	12		$	1,751,165		$	627,429		$	549,886		$	77,543
Energy Costs:
Fuel for power generation	400,936			—			285,799			115,137			115,137			—
Purchased power	486,894			—			388,494			98,400			98,400			—
Gas purchased for resale	46,491			—			—			46,491			—			46,491
Deferred Energy	(30,285		)	—			(15,461		)	(14,824		)	(13,854		)	(970		)
Energy efficiency program costs	76,609			—			65,466			11,143			11,143			—
Total Costs	$	980,645		$	—		$	724,298		$	256,347		$	210,826		$	45,521
Gross Margin	$	1,397,961		$	12		$	1,026,867		$	371,082		$	339,060		$	32,022
Other operating expenses	307,080			2,382			200,484			104,214
Maintenance	76,190			—			52,594			23,596
Depreciation and amortization	281,690			—			201,096			80,594
Taxes other than income	44,457			282			26,793			17,382
Operating Income (Loss)	$	688,544		$	(2,652	)	$	545,900		$	145,296

REGULATORY_ACTIONS_Tables

REGULATORY ACTIONS (Tables)	9 Months Ended
	Sep. 30, 2013
REGULATORY ACTIONS [Abstract]	'
Summary of Deferred Energy Amounts	'
	The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2013 (dollars in thousands):
		September 30, 2013
		NVE Total				NPC Electric				SPPC Electric				SPPC Gas
	Deferred Energy
	Cumulative Deferred Balance authorized in 2013 DEAA	$	(152,990	)		$	(102,227	)		$	(32,693	)		$	(18,070	)
	2013 Amortization	111,977				69,288				23,695				18,994
	2013 Deferred Energy Under Collections (1)	118,397				95,465				19,697				3,235
	Deferred Energy Balance at September 30, 2013 - Subtotal	$	77,384			$	62,526			$	10,699			$	4,159
	Reinstatement of deferred energy (effective 6/07, 10 years)	89,906				89,906				—				—
	Total Deferred Energy	$	167,290			$	152,432			$	10,699			$	4,159
	Current Assets
	Deferred energy	$	82,235			$	68,391			$	10,322			$	3,522
	Non-current Assets
	Deferred energy	85,055				84,041				377				637
	Total Net Deferred Energy	$	167,290			$	152,432			$	10,699			$	4,159
	(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 the Financial Statements in the 2012 Form 10-K.
Summary of Rate Filings	'
	The September PUCN order includes the following changes in revenue requirement (dollars in millions):
		Effective		Authorized				Present				$ Change in
		Date		Revenue				Revenue				Revenue
				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				5.6				0.4
	EEPR Amortization (1)	Oct. 2013		(2.1		)		1.8				(3.9		)
	EEIR Base (2)	Oct. 2013		5.5				4.7				0.8
	EEIR Amortization (3)	Oct. 2013		(3.7		)		1.9				(5.6		)
	Total Revenue Requirement			$	55.4			$	64.7			$	(9.3	)
	-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.
	-2	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.
	-3	Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.
	The September PUCN order includes the following changes in revenue requirement (dollars in millions):
		Effective		Authorized				Present				$ Change in
		Date		Revenue				Revenue				Revenue
				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				(38.9		)
	EEIR Base (2)	Oct. 2013		15.1				10.6				4.5
	EEIR Amortization (3)	Oct. 2013		(17.2		)		10.7				(27.9		)
	Total Revenue Requirement			$	58			$	117.5			$	(59.5	)
	(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.
	(2)	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.
	(3)	Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Schedule of Long-term Debt	'
	NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands):
					September 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	5.95	%	2016	210,000			—		210,000			—			210,000			—		210,000			—
	NPC Series N	6.65	%	2036	370,000			—		370,000			—			370,000			—		370,000			—
	NPC Series O	6.5	%	2018	325,000			—		325,000			—			325,000			—		325,000			—
	NPC Series R	6.75	%	2037	350,000			—		350,000			—			350,000			—		350,000			—
	NPC Series S	6.5	%	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	5.45	%	2041	250,000			—		250,000			—			250,000			—		250,000			—
	SPPC Series M	6	%	2016	450,000			—		—			450,000			450,000			—		—			450,000
	SPPC Series P	6.75	%	2037	251,742			—		—			251,742			251,742			—		—			251,742
	SPPC Series Q	5.45	%	2013	—			—		—			—			250,000			—		—			250,000
	SPPC Series T	3.375	%	2023	250,000			—		—			250,000			—			—		—			—
	Variable Rate Debt (Secured by General and Refunding Mortgage Securities)
	NPC IDRB Series 2000A			2020	—			—		—			—			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	6.25	%	2020	315,000			315,000		—			—			315,000			315,000		—			—
	NVE Term Loan	2.56	%	2014	195,000			195,000		—			—			195,000			195,000		—			—
	Obligations under capital leases				38,415			—		36,571			1,844			44,258			—		42,908			1,350
	Unamortized bond premium and discount (net)				759			—		(9,080		)	9,839			1,631			—		(9,827		)	11,458
	Current maturities				(129,457		)	—		(129,186		)	(271		)	(356,283		)	—		(106,048		)	(250,235		)
	Total Long-Term Debt				$	4,791,809		$	510,000	$	3,103,980		$	1,177,829		$	4,669,798		$	510,000	$	3,230,808		$	928,990

RETIREMENT_PLAN_AND_POSTRETIRE1

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2013
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Net Benefit Costs	'
	This summary is based on a December 31, measurement date (dollars in thousands):
	NVE
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	15,396		$	13,220		$	1,980		$	1,787
	Interest cost	27,911			30,684			5,030			5,715
	Expected return on plan assets	(38,124		)	(37,341		)	(5,060		)	(4,690		)
	Amortization of prior service cost	(2,162		)	(2,173		)	(2,857		)	(2,961		)
	Amortization of net loss	14,391			10,418			2,671			2,193
	Net periodic benefit cost	$	17,412		$	14,808		$	1,764		$	2,044
	The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.5% and 35.0% respectively.
	NPC
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	8,283		$	7,072		$	1,167		$	1,050
	Interest cost	13,358			14,643			1,667			1,807
	Expected return on plan assets	(18,810		)	(18,711		)	(1,892		)	(1,775		)
	Amortization of prior service cost	(1,358		)	(1,367		)	(69		)	687
	Amortization of net loss	6,351			4,089			867			662
	Net periodic benefit cost	$	7,824		$	5,726		$	1,740		$	2,431
	The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.9% and 36.9% respectively.
	SPPC
		Pension Benefits						Other Post-Retirement Benefits
		For the Three Months Ended September 30						For the Three Months Ended September 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 Post-Retirement Benefits
		For the Nine Months Ended September 30						For the Nine Months Ended September 30
		2013			2012			2013			2012
	Service cost	$	5,778		$	5,086		$	752		$	682
	Interest cost	13,676			15,130			3,310			3,848
	Expected return on plan assets	(18,486		)	(17,813		)	(3,065		)	(2,823		)
	Amortization of prior service cost	(831		)	(831		)	(2,798		)	(3,658		)
	Amortization of net loss	7,502			6,078			1,777			1,511
	Net periodic benefit cost	$	7,639		$	7,650		$	(24	)	$	(440	)
	The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.

EARNINGS_PER_SHARE_NVE_Tables

EARNINGS PER SHARE (NVE) (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted	'
		Three Months Ended September 30,				Nine Months Ended September 30,
		2013		2012		2013		2012
	Basic EPS
	Numerator ($000)
	Net Income	$	187,234	$	223,170	$	271,942	$	304,782
	Denominator
	Weighted average number of common shares outstanding	235,578,310		235,961,402		235,421,933		235,986,874
	Per Share Amounts
	Net Income per share - basic	$	0.79	$	0.95	$	1.16	$	1.29
	Diluted EPS
	Numerator ($000)
	Net Income	$	187,234	$	223,170	$	271,942	$	304,782
	Denominator(1)
	Weighted average number of shares outstanding before dilution	235,578,310		235,961,402		235,421,933		235,986,874
	Stock options	61,927		39,256		46,537		37,592
	Non-Employee Director stock plan	190,705		166,829		185,337		160,257
	Employee stock purchase plan	4,149		6,742		5,831		6,785
	Restricted Shares	412,000		584,750		487,667		533,750
	Performance Shares	1,358,423		1,362,753		1,191,734		1,125,272
	Diluted Weighted Average Number of Shares	237,605,514		238,121,732		237,339,039		237,850,530
	Per Share Amounts
	Net income per share - diluted	$	0.79	$	0.94	$	1.15	$	1.28
	-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 September 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

COMMON_STOCK_AND_OTHER_PAIDIN_1

COMMON STOCK AND OTHER PAID-IN CAPITAL (Tables)	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
Dividend Declarations	'
	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
	November 6, 2013	$0.19	December 18, 2013	December 3, 2013

MERGER_RELATED_ACTIVITIES_Deta

MERGER RELATED ACTIVITIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Merger Related Activities [Line Items]	'	'	'	'
Merger related costs	$7,857,000	$0	$21,409,000	$0
Nevada Power Company	'	'	'	'
Merger Related Activities [Line Items]	'	'	'	'
Merger related costs	5,620,000	0	14,487,000	0
Sierra Pacific Power Company	'	'	'	'
Merger Related Activities [Line Items]	'	'	'	'
Merger related costs	2,008,000	0	5,528,000	0
MidAmerican Merger	'	'	'	'
Merger Related Activities [Line Items]	'	'	'	'
Merger Agreement Date	'	'	'May 29, 2013	'
Expected Merger Closing Date	'	'	'in late 2013 or first quarter of 2014	'
Merger Closing Conditions	'	'	' the approval of the MidAmerican Merger Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVEbs stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied; 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 JulyB 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.B 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	'
Shareholder approval date	'September 25, 2013	'	'September 25, 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 to 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.B In addition, the covenants contain several restrictions that apply unless MEHCbs 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 and limitations on increasing our common stock dividend payout.	'
Merger Description	'	'	'On MayB 29, 2013, NVE entered into the MidAmerican Merger Agreement.B The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation.B Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.B The closing is expected to occur in late 2013 or during the first quarter of 2014.	'
MidAmerican Merger | Parent Company	'	'	'	'
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 | Nevada Power Company	'	'	'	'
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 | Sierra Pacific Power Company	'	'	'	'
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	'	'	5.51%	'
One Company Merger | Nevada Power Company	'	'	'	'
Merger Related Activities [Line Items]	'	'	'	'
Merger Description	'	'	'NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (bOne Company Mergerb) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.	'
One Company Merger | Sierra Pacific Power Company	'	'	'	'
Merger Related Activities [Line Items]	'	'	'	'
Merger Description	'	'	'NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (bOne Company Mergerb) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.	'

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]	'	'	'	'
Operating Revenues	$1,013,151	$1,026,488	$2,329,011	$2,378,606
Energy Costs:	'	'	'	'
Fuel for power generation	217,954	171,316	554,181	400,936
Purchased power	205,970	205,686	498,141	486,894
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	-55,270	-29,036	-221,022	-30,285
Energy efficiency program costs	16,042	32,584	38,486	76,609
Regulatory Disallowances	17,335	0	17,335	0
Total Costs	409,414	385,932	949,398	980,645
Gross Margin	603,737	640,556	1,379,613	1,397,961
Merger related costs	7,857	0	21,409	0
Other Cost and Expense, Operating	106,068	100,108	317,538	307,080
Utilities Operating Expense, Maintenance	17,176	19,014	66,128	76,190
Depreciation, Depletion and Amortization, Nonproduction	96,801	94,512	291,687	281,690
Taxes, Other	14,214	15,682	46,536	44,457
OPERATING INCOME	361,621	411,240	636,315	688,544
Unallocated Amount to Segment	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Operating Revenues	3	4	10	12
Energy Costs:	'	'	'	'
Total Costs	0	0	0	0
Gross Margin	3	4	10	12
Merger related costs	229	'	1,394	'
Other Cost and Expense, Operating	830	608	2,747	2,382
Taxes, Other	57	45	318	282
OPERATING INCOME	-1,113	-649	-4,449	-2,652
NPC Electric	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Operating Revenues	786,142	802,334	1,695,129	1,751,165
Energy Costs:	'	'	'	'
Fuel for power generation	163,127	123,992	412,904	285,799
Purchased power	172,582	171,687	383,386	388,494
Deferred energy	-45,381	-22,685	-154,484	-15,461
Energy efficiency program costs	13,998	28,492	32,807	65,466
Regulatory Disallowances	11,866	'	11,866	'
Total Costs	316,192	301,486	686,479	724,298
Gross Margin	469,950	500,848	1,008,650	1,026,867
Merger related costs	5,620	'	14,487	'
Other Cost and Expense, Operating	70,844	65,372	208,336	200,484
Utilities Operating Expense, Maintenance	11,208	12,533	45,172	52,594
Depreciation, Depletion and Amortization, Nonproduction	68,849	66,975	207,915	201,096
Taxes, Other	8,213	9,743	27,804	26,793
OPERATING INCOME	305,216	346,225	504,936	545,900
SPPC Total	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Operating Revenues	227,006	224,150	633,872	627,429
Energy Costs:	'	'	'	'
Fuel for power generation	54,827	47,324	141,277	115,137
Purchased power	33,388	33,999	114,755	98,400
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	-9,889	-6,351	-66,538	-14,824
Energy efficiency program costs	2,044	4,092	5,679	11,143
Regulatory Disallowances	5,469	'	5,469	'
Total Costs	93,222	84,446	262,919	256,347
Gross Margin	133,784	139,704	370,953	371,082
Merger related costs	2,008	'	5,528	'
Other Cost and Expense, Operating	34,394	34,128	106,455	104,214
Utilities Operating Expense, Maintenance	5,968	6,481	20,956	23,596
Depreciation, Depletion and Amortization, Nonproduction	27,952	27,537	83,772	80,594
Taxes, Other	5,944	5,894	18,414	17,382
OPERATING INCOME	57,518	65,664	135,828	145,296
SPPC Electric	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Electric Domestic Regulated Revenue	213,463	212,073	560,392	549,886
Energy Costs:	'	'	'	'
Fuel for power generation	54,827	47,324	141,277	115,137
Purchased power	33,388	33,999	114,755	98,400
Deferred energy	-7,925	-5,498	-44,223	-13,854
Energy efficiency program costs	2,044	4,092	5,679	11,143
Regulatory Disallowances	5,469	'	5,469	'
Total Costs	87,803	79,917	222,957	210,826
Gross Margin	125,660	132,156	337,435	339,060
SPPC Gas	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Gas Domestic Regulated Revenue	13,543	12,077	73,480	77,543
Energy Costs:	'	'	'	'
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	-1,964	-853	-22,315	-970
Total Costs	5,419	4,529	39,962	45,521
Gross Margin	$8,124	$7,548	$33,518	$32,022

REGULATORY_ACTIONS_Deferred_En

REGULATORY ACTIONS, Deferred Energy (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Nevada Deferred Energy	'		'
Cumulative balance authorized in DEAA	($152,990)		'
Amortization	111,977		'
Deferred Energy Under Collection	118,397	[1]	'
Nevada Deferred Energy Balance at period end	77,384		'
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906		'
Total Deferred Energy	167,290		'
Deferred Assets	'		'
Deferred energy costs current	82,235		0
Deferred Energy Costs Non Current	85,055		87,072
Liabilities, Current [Abstract]	'		'
Deferred energy	0		136,865
NPC Electric	'		'
Nevada Deferred Energy	'		'
Cumulative balance authorized in DEAA	-102,227		'
Amortization	69,288		'
Deferred Energy Under Collection	95,465	[1]	'
Nevada Deferred Energy Balance at period end	62,526		'
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906		'
Total Deferred Energy	152,432		'
Deferred Assets	'		'
Deferred energy costs current	68,391		'
Deferred Energy Costs Non Current	84,041		'
SPPC Electric	'		'
Nevada Deferred Energy	'		'
Cumulative balance authorized in DEAA	-32,693		'
Amortization	23,695		'
Deferred Energy Under Collection	19,697	[1]	'
Nevada Deferred Energy Balance at period end	10,699		'
Reinstatement of deferred energy (effective 6/07, 10 years)	0		'
Total Deferred Energy	10,699		'
Deferred Assets	'		'
Deferred Energy Electric Current	10,322		'
Deferred Energy Costs Non Current	377		'
SPPC Gas	'		'
Nevada Deferred Energy	'		'
Cumulative balance authorized in DEAA	-18,070		'
Amortization	18,994		'
Deferred Energy Under Collection	3,235	[1]	'
Nevada Deferred Energy Balance at period end	4,159		'
Reinstatement of deferred energy (effective 6/07, 10 years)	0		'
Total Deferred Energy	4,159		'
Deferred Assets	'		'
Deferred Energy Gas Current	3,522		'
Deferred Energy Costs Gas Non Current	$637		'
[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 the Financial Statements in the 2012 Form 10-K.

REGULATORY_ACTIONS_Merger_Rela

REGULATORY ACTIONS, Merger Related and Financing Application (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Nevada Power Company	'
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
Sierra Pacific Power Company	'
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 | Nevada Power Company	'
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
Expected Hearing Date	1-Nov-13
Days To Respond	'180 days
AdditionalDaysToRespond	'180 days
MidAmerican Merger | Sierra Pacific Power Company	'
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
Expected Hearing Date	1-Nov-13
Days To Respond	'180 days
AdditionalDaysToRespond	'180 days
One Company Merger | Nevada Power Company	'
Merger Related Activities [Line Items]	'
Filing Date of PUCN filing	'May 2013
Filing Date of FERC filing	'May 2013
Expected Hearing Date	1-Feb-14
One Company Merger | Sierra Pacific Power Company	'
Merger Related Activities [Line Items]	'
Filing Date of PUCN filing	'May 2013
Filing Date of FERC filing	'May 2013
Expected Hearing Date	1-Feb-14

REGULATORY_ACTIONS_Summary_of_

REGULATORY ACTIONS, Summary of Regulatory Actions (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	$17,335,000		$0	$17,335,000		$0
Nevada Power Company	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Authorized Revenue Requirement	58,000,000		'	58,000,000		'
Present Revenue Requirement	117,500,000		'	117,500,000		'
$ Change in Revenue Requirement	-59,500,000		'	-59,500,000		'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	11,866,000		0	11,866,000		0
Nevada Power Company | DEAA [Member]	'		'	'		'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	1,100,000		'	1,100,000		'
Nevada Power Company | REPR [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	28,400,000	[1]	'	28,400,000	[1]	'
Present Revenue Requirement	38,700,000	[1]	'	38,700,000	[1]	'
$ Change in Revenue Requirement	-10,300,000	[1]	'	-10,300,000	[1]	'
Nevada Power Company | TRED [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	15,700,000	[1]	'	15,700,000	[1]	'
Present Revenue Requirement	15,900,000	[1]	'	15,900,000	[1]	'
$ Change in Revenue Requirement	-200,000	[1]	'	-200,000	[1]	'
Nevada Power Company | EEPR Base [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	45,900,000	[1]	'	45,900,000	[1]	'
Present Revenue Requirement	32,600,000	[1]	'	32,600,000	[1]	'
$ Change in Revenue Requirement	13,300,000	[1]	'	13,300,000	[1]	'
Nevada Power Company | EEPR Amortization [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	-29,900,000	[1]	'	-29,900,000	[1]	'
Present Revenue Requirement	9,000,000	[1]	'	9,000,000	[1]	'
$ Change in Revenue Requirement	-38,900,000	[1]	'	-38,900,000	[1]	'
Nevada Power Company | EEIR Base [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[2]	'
Authorized Revenue Requirement	15,100,000	[2]	'	15,100,000	[2]	'
Present Revenue Requirement	10,600,000	[2]	'	10,600,000	[2]	'
$ Change in Revenue Requirement	4,500,000	[2]	'	4,500,000	[2]	'
Nevada Power Company | EEIR Amortization [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[3]	'
Authorized Revenue Requirement	-17,200,000	[3]	'	-17,200,000	[3]	'
Present Revenue Requirement	10,700,000	[3]	'	10,700,000	[3]	'
$ Change in Revenue Requirement	-27,900,000	[3]	'	-27,900,000	[3]	'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	10,800,000		'	10,800,000		'
Regulatory reserve	11,200,000		'	11,200,000		'
Sierra Pacific Power Company	'		'	'		'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	5,469,000		0	5,469,000		0
SPPC Electric	'		'	'		'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	5,469,000		'	5,469,000		'
SPPC Electric | GRC [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'January 1, 2014		'
SPPC Electric | Sierra Pacific Power Company	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Authorized Revenue Requirement	55,400,000		'	55,400,000		'
Present Revenue Requirement	64,700,000		'	64,700,000		'
$ Change in Revenue Requirement	-9,300,000		'	-9,300,000		'
SPPC Electric | Sierra Pacific Power Company | DEAA [Member]	'		'	'		'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	100,000		'	100,000		'
SPPC Electric | Sierra Pacific Power Company | REPR [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	42,300,000	[1]	'	42,300,000	[1]	'
Present Revenue Requirement	44,400,000	[1]	'	44,400,000	[1]	'
$ Change in Revenue Requirement	-2,100,000	[1]	'	-2,100,000	[1]	'
SPPC Electric | Sierra Pacific Power Company | TRED [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	7,400,000	[1]	'	7,400,000	[1]	'
Present Revenue Requirement	6,300,000	[1]	'	6,300,000	[1]	'
$ Change in Revenue Requirement	1,100,000	[1]	'	1,100,000	[1]	'
SPPC Electric | Sierra Pacific Power Company | EEPR Base [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	6,000,000	[1]	'	6,000,000	[1]	'
Present Revenue Requirement	5,600,000	[1]	'	5,600,000	[1]	'
$ Change in Revenue Requirement	400,000	[1]	'	400,000	[1]	'
SPPC Electric | Sierra Pacific Power Company | EEPR Amortization [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[1]	'
Authorized Revenue Requirement	-2,100,000	[1]	'	-2,100,000	[1]	'
Present Revenue Requirement	1,800,000	[1]	'	1,800,000	[1]	'
$ Change in Revenue Requirement	-3,900,000	[1]	'	-3,900,000	[1]	'
SPPC Electric | Sierra Pacific Power Company | EEIR Base [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[4]	'
Authorized Revenue Requirement	5,500,000	[4]	'	5,500,000	[4]	'
Present Revenue Requirement	4,700,000	[4]	'	4,700,000	[4]	'
$ Change in Revenue Requirement	800,000	[4]	'	800,000	[4]	'
SPPC Electric | Sierra Pacific Power Company | EEIR Amortization [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'Oct. 2013	[3]	'
Authorized Revenue Requirement	-3,700,000	[3]	'	-3,700,000	[3]	'
Present Revenue Requirement	1,900,000	[3]	'	1,900,000	[3]	'
$ Change in Revenue Requirement	-5,600,000	[3]	'	-5,600,000	[3]	'
Energy And Gas Related Regulatory Filings [Abstract]	'		'	'		'
Regulatory Disallowances	5,500,000		'	5,500,000		'
Regulatory reserve	4,000,000		'	4,000,000		'
SPPC Gas	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
$ Change in Revenue Requirement	($200,000)		'	($200,000)		'
SPPC Gas | GRC [Member]	'		'	'		'
Revenue Requirement Subject To Change:	'		'	'		'
Effective Date	'		'	'January 1, 2014		'
[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.
[2]	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.
[3]	Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.
[4]	The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

REGULATORY_General_Rate_Cases_

REGULATORY, General Rate Cases (Details) (GRC [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
SPPC Electric	'
Summary of General Rate Case [Line Items]	'
Anticipated Effective Date of Rate Filing	'January 1, 2014
Requested Increase Decrease In General Rates	($4.70)
Percentage Overall Increase Decrease In General Rates	-0.70%
Requested Rate Of Return	7.74%
Requested Return On Equity	10.40%
General Rate Case Hearing Date	'October 2013
SPPC Gas	'
Summary of General Rate Case [Line Items]	'
Anticipated Effective Date of Rate Filing	'January 1, 2014
Requested Increase Decrease In General Rates	$6
Percentage Overall Increase Decrease In General Rates	6.10%
Requested Rate Of Return	7.72%
Requested Return On Equity	10.35%
General Rate Case Hearing Date	'October 2013

REGULATORY_ACTIONS_FERC_Matter

REGULATORY ACTIONS, FERC Matters (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Nevada Power Company | FERC Filing 2012 [Member]	'
FERC Matters [Abstract]	'
Transmission Rate Case Filing Date	'October 2012
Anticipated Effective Date of Rate Filing	'June 1, 2013
Nevada Power Company | 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 | 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
FERC approval date	'August 29, 2013
Sierra Pacific Power Company | 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

LONGTERM_DEBT_Debt_Instruments

LONG-TERM DEBT, Debt Instruments (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	($759,000)	($1,631,000)
Current maturities	-129,457,000	-356,283,000
Total Long-Term Debt	4,791,809,000	4,669,798,000
Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
Stated interest rate (in hundredths)	5.88%	'
Maturity date	'2015	'
Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	210,000,000	210,000,000
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	370,000,000	370,000,000
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	325,000,000	325,000,000
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	350,000,000	350,000,000
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	500,000,000	500,000,000
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	125,000,000	125,000,000
Stated interest rate (in hundredths)	7.38%	'
Maturity date	'2014	'
Secured, General and Refunding Mortgage Securities, Series V [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	500,000,000	500,000,000
Stated interest rate (in hundredths)	7.13%	'
Maturity date	'2019	'
Secured, General and Refunding Mortgage Securities, Series X [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
Stated interest rate (in hundredths)	5.38%	'
Maturity date	'2040	'
Secured, General and Refunding Mortgage Securities, Series Y [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
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	450,000,000	450,000,000
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	251,742,000	251,742,000
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	0	250,000,000
Stated interest rate (in hundredths)	5.45%	'
Maturity date	'2013	'
General and Refunding Mortgage Securities SPPC Series T [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	0
Stated interest rate (in hundredths)	3.38%	'
Maturity date	'2023	'
Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	'	98,100,000
Maturity date	'2020	'
Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	37,700,000	37,700,000
Maturity date	'2036	'
Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	37,975,000	37,975,000
Maturity date	'2032	'
Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	58,200,000	58,200,000
Maturity date	'2031	'
Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	75,000,000	75,000,000
Maturity date	'2036	'
Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	81,475,000	81,475,000
Maturity date	'2036	'
NVE Senior Notes due 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	195,000,000	195,000,000
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	315,000,000	315,000,000
Stated interest rate (in hundredths)	6.25%	'
Maturity date	'2020	'
Capital Lease Obligations [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	38,415,000	44,258,000
Parent Company	'	'
Debt Instrument [Line Items]	'	'
Total Long-Term Debt	510,000,000	510,000,000
Parent Company | NVE Senior Notes due 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	195,000,000	195,000,000
Parent Company | NVE Senior Notes due 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	315,000,000	315,000,000
Nevada Power Company	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	9,080,000	9,827,000
Current maturities	-129,186,000	-106,048,000
Total Long-Term Debt	3,103,980,000	3,230,808,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	210,000,000	210,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series N [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	370,000,000	370,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series O [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	325,000,000	325,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series R [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	350,000,000	350,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series S [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	500,000,000	500,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series U [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	125,000,000	125,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series V [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	500,000,000	500,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series X [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series Y [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	'	98,100,000
Notice Of Redemption	100,000,000	'
Notice Of Redemption Date	'July 1, 2013	'
Redemption Date	'August 1, 2013	'
Redemption Percentage	100.00%	'
Amount of debt redeemed	98,100,000	'
Nevada Power Company | Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	37,700,000	37,700,000
Nevada Power Company | Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	37,975,000	37,975,000
Nevada Power Company | Capital Lease Obligations [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	36,571,000	42,908,000
Sierra Pacific Power Company	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, Unamortized Discount (Premium), Net	-9,839,000	-11,458,000
Current maturities	-271,000	-250,235,000
Total Long-Term Debt	1,177,829,000	928,990,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	450,000,000	450,000,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	251,742,000	251,742,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	0	250,000,000
Redemption Date	'September 1, 2013	'
Amount of debt redeemed	250,000,000	'
Sierra Pacific Power Company | General and Refunding Mortgage Securities SPPC Series T [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	250,000,000	0
Net Proceeds used to redeem debt	247,900,000	'
Debt Instrument, Issuance Date	1-Aug-13	'
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	58,200,000	58,200,000
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	75,000,000	75,000,000
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	81,475,000	81,475,000
Sierra Pacific Power Company | Capital Lease Obligations [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt including current maturities	$1,844,000	$1,350,000

FAIR_VALUE_OF_FINANCIAL_INSTRU1

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Billions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	$5.60	$5.90
Nevada Power Company	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	3.7	4.1
Sierra Pacific Power Company	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	$1.30	$1.30

RETIREMENT_PLAN_AND_POSTRETIRE2

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Components of Net Periodic Cost and Expected Benefit Payments (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Average percentage of net periodic costs capitalized [Abstract]	'	'	'	'
Average percentage of net periodic costs capitalized (in hundredths)	'	'	34.50%	35.00%
DefinedBenefitPlanEffectOfPlanAmendmentOnAccumulatedBenefitObligation	$21,500,000	'	$21,500,000	'
United States Pension Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	5,132,000	4,406,000	15,396,000	13,220,000
Interest cost	9,303,000	10,228,000	27,911,000	30,684,000
Expected return on plan assets	-12,708,000	-12,447,000	-38,124,000	-37,341,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-720,000	-724,000	-2,162,000	-2,173,000
Actuarial (gain)/loss	4,797,000	3,473,000	14,391,000	10,418,000
Total net benefit cost	5,804,000	4,936,000	17,412,000	14,808,000
Average percentage of net periodic costs capitalized [Abstract]	'	'	'	'
PensionAndOtherPostretirementBenefitContributions	'	'	20,000,000	15,000,000
United States Postretirement Benefit Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	660,000	595,000	1,980,000	1,787,000
Interest cost	1,677,000	1,905,000	5,030,000	5,715,000
Expected return on plan assets	-1,687,000	-1,563,000	-5,060,000	-4,690,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-952,000	-987,000	-2,857,000	-2,961,000
Actuarial (gain)/loss	890,000	731,000	2,671,000	2,193,000
Total net benefit cost	588,000	681,000	1,764,000	2,044,000
Average percentage of net periodic costs capitalized [Abstract]	'	'	'	'
PensionAndOtherPostretirementBenefitContributions	'	'	5,000,000	7,100,000
Nevada Power Company	'	'	'	'
Average percentage of net periodic costs capitalized [Abstract]	'	'	'	'
Average percentage of net periodic costs capitalized (in hundredths)	'	'	35.90%	36.90%
Nevada Power Company | United States Pension Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	2,761,000	2,358,000	8,283,000	7,072,000
Interest cost	4,453,000	4,881,000	13,358,000	14,643,000
Expected return on plan assets	-6,270,000	-6,237,000	-18,810,000	-18,711,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-453,000	-456,000	-1,358,000	-1,367,000
Actuarial (gain)/loss	2,117,000	1,363,000	6,351,000	4,089,000
Total net benefit cost	2,608,000	1,909,000	7,824,000	5,726,000
Nevada Power Company | United States Postretirement Benefit Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	389,000	350,000	1,167,000	1,050,000
Interest cost	556,000	602,000	1,667,000	1,807,000
Expected return on plan assets	-631,000	-592,000	-1,892,000	-1,775,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-23,000	229,000	-69,000	687,000
Actuarial (gain)/loss	289,000	221,000	867,000	662,000
Total net benefit cost	580,000	810,000	1,740,000	2,431,000
Sierra Pacific Power Company	'	'	'	'
Average percentage of net periodic costs capitalized [Abstract]	'	'	'	'
Average percentage of net periodic costs capitalized (in hundredths)	'	'	35.60%	35.10%
Sierra Pacific Power Company | United States Pension Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	1,926,000	1,695,000	5,778,000	5,086,000
Interest cost	4,558,000	5,043,000	13,676,000	15,130,000
Expected return on plan assets	-6,162,000	-5,937,000	-18,486,000	-17,813,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-277,000	-277,000	-831,000	-831,000
Actuarial (gain)/loss	2,501,000	2,026,000	7,502,000	6,078,000
Total net benefit cost	2,546,000	2,550,000	7,639,000	7,650,000
Sierra Pacific Power Company | United States Postretirement Benefit Plans of US Entity, Defined Benefit	'	'	'	'
Net periodic benefit cost [Abstract]	'	'	'	'
Service cost	251,000	227,000	752,000	682,000
Interest cost	1,104,000	1,283,000	3,310,000	3,848,000
Expected return on plan assets	-1,022,000	-941,000	-3,065,000	-2,823,000
Amortization of:	'	'	'	'
Prior service (credit)/cost	-933,000	-1,220,000	-2,798,000	-3,658,000
Actuarial (gain)/loss	592,000	504,000	1,777,000	1,511,000
Total net benefit cost	($8,000)	($147,000)	($24,000)	($440,000)

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES, Environmental (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
Environmental [Abstract]	'
Regional Haze	$77.10
Nevada Power Company	'
Environmental [Abstract]	'
Reclamation estimate of coal washing and load-out facility site	4
Nevada Power Company | Navajo Generating Station	'
Environmental [Abstract]	'
Ownership interest in generating stations (in hundredths)	11.30%
Regional Haze	1,100
Sierra Pacific Power Company | Valmy Generating Station	'
Environmental [Abstract]	'
Ownership interest in generating stations (in hundredths)	50.00%
Mercury Air Toxic Standards Costs	$6.40

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES, Litigation Contingencies and Other Commitments (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Capital Projects	'
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
November 2005 Land Investors [Abstract]	'
Amount awarded unpaid rent	1,000,000
Amount awarded inverse condemnation and interest	5,100,000
Nevada Power Company [Member] | Capital Projects	'
ON Line TUA [Abstract]	'
Capitalized construction costs	370,800,000
Nevada Power Company [Member] | Navajo Generating Station	'
Royalty claim [Abstract]	'
Ownership interest in generating stations (in hundredths)	11.30%
Sierra Pacific Power Company	'
Farad Dam [Abstract]	'
Number of hydro generating units sold	4
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	'3 years
ReplacementCost	19,800,000
Sierra Pacific Power Company | Capital Projects	'
ON Line TUA [Abstract]	'
Capitalized construction costs	$19,400,000

EARNINGS_PER_SHARE_NVE_Details

EARNINGS PER SHARE (NVE) (Details) (USD $)	3 Months Ended				9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Numerator	'		'		'		'
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$187,234		$223,170		$271,942		$304,782
Denominator	'		'		'		'
Weighted Average Shares of Common Stock Outstanding - basic	235,578,310		235,961,402		235,421,933		235,986,874
Per Share Amounts	'		'		'		'
Net income per share - basic	$0.79		$0.95		$1.16		$1.29
Numerator	'		'		'		'
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$187,234		$223,170		$271,942		$304,782
Denominator	'		'		'		'
Weighted Average Number of Shares Outstanding, Basic	235,578,310		235,961,402		235,421,933		235,986,874
Stock options (in shares)	61,927		39,256		46,537		37,592
Non-Employee Director stock plan (in shares)	190,705		166,829		185,337		160,257
Employee stock purchase plan (in shares)	4,149		6,742		5,831		6,785
Restricted Shares (in shares)	412,000		584,750		487,667		533,750
Performance Shares (in shares)	1,358,423		1,362,753		1,191,734		1,125,272
Weighted Average Number of Shares Outstanding, Diluted	237,605,514	[1]	238,121,732	[1]	237,339,039	[1]	237,850,530	[1]
Per Share Amounts	'		'		'		'
Net income per share - diluted	$0.79		$0.94		$1.15		$1.28
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	327,503		'		329,382		'
[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 September 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

COMMON_STOCK_AND_OTHER_PAIDIN_2

COMMON STOCK AND OTHER PAID-IN CAPITAL (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Nov. 06, 2013

Dec. 18, 2013

Dec. 03, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Nov. 06, 2013

Sep. 30, 2013

Nov. 06, 2013

Subsequent Event

Subsequent Event

Subsequent Event

Treasury stock

Treasury stock

Nevada Power Company

Nevada Power Company

Sierra Pacific Power Company

Sierra Pacific Power Company

Scenario, Forecast

Scenario, Forecast

Subsequent Event

Subsequent Event

Dividends Payable [Line Items]

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Dividends Declared Per Share of Common Stock

$0.19

$0.19

$0.19

$0.17

$0.57

$0.47

$0.19

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Dividends [Abstract]

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Dividends Payable, Date to be Paid, Day, Month and Year

18-Sep-13

19-Jun-13

20-Mar-13

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18-Dec-13

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Dividends Payable, Date of Record, Day, Month and Year

3-Sep-13

4-Jun-13

5-Mar-13

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3-Dec-13

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Cash Dividends Paid to Parent Company by Consolidated Subsidiaries

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$105,000,000

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$40,000,000

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Dividend declared to parent company

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73,000,000

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37,000,000

Declaration date

1-Aug-13

8-May-13

7-Feb-13

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6-Nov-13

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6-Nov-13

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6-Nov-13

Common stock repurchased (shares)

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325,178

252,000

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Common stock repurchased

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($6,329,000)

($4,509,000)

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($6,329,000)

($4,509,000)

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Dividend Reinvestment and Employee Benefits (in shares)

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827,097

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