Nevada Power (NVP) 10-K31 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 28, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'Nevada Power Company	'	'
Entity Central Index Key	'0000071180	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	1,000	'
Entity Public Float	'	'	$0
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$126	$201
Accounts receivable, net	227	249
Inventories	73	78
Regulatory assets	81	0
Deferred income taxes	152	49
Other current assets	39	28
Total current assets	698	605
Property, plant and equipment, net	6,992	6,912
Regulatory assets	1,057	1,028
Other assets	88	96
Total assets	8,835	8,641
Current liabilities:	'	'
Accounts payable	240	243
Accrued interest	61	65
Accrued property, income and other taxes	29	6
Accrued employee expenses	6	15
Regulatory liabilities	74	86
Current portion of long-term debt	22	106
Customer deposits and other	74	53
Total current liabilities	506	574
Long-term debt	3,555	3,231
Regulatory liabilities	312	323
Deferred income taxes	1,298	1,102
Other long-term liabilities	274	489
Total liabilities	5,945	5,719
Commitments and contingencies (Note 16)	'	'
Shareholder's equity:	'	'
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding as of December 31, 2013 and 2012	0	0
Other paid-in capital	2,308	2,308
Retained earnings	586	619
Accumulated other comprehensive loss, net	-4	-5
Total shareholder's equity	2,890	2,922
Total liabilities and shareholder's equity	$8,835	$8,641

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Common stock, stated value	$1	$1
Common stock, shares authorized	1,000	1,000
Common stock, shares issued	1,000	1,000
Common stock, shares outstanding	1,000	1,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Operating revenue	$2,092	$2,145	$2,054
Operating costs and expenses:	'	'	'
Cost of fuel, energy and capacity	835	813	959
Operating and maintenance expense	455	423	362
Depreciation and amortization	277	270	252
Property and other taxes	38	37	37
Merger-related expenses	52	0	0
Total operating costs and expenses	1,657	1,543	1,610
Operating income	435	602	444
Other income (expense):	'	'	'
Interest expense, net of allowance for debt funds	-209	-210	-222
Allowance for equity funds	8	7	8
Other, net	5	-3	-26
Total other income (expense)	-196	-206	-240
Income before income tax expense	239	396	204
Income tax expense	94	138	71
Net income	$145	$258	$133

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Shareholder's Equity (USD $)	Total	Common Stock	Other Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss, Net
In Millions, except Share data, unless otherwise specified	Total	Common Stock	Other Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss, Net
Balance at Dec. 31, 2010	$2,761	$0	$2,254	$511	($4)
Balance (shares) at Dec. 31, 2010	'	1,000	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income	133	'	'	133	'
Contribution	54	'	54	'	'
Dividends declared	-99	'	'	-99	'
Balance at Dec. 31, 2011	2,849	0	2,308	545	-4
Balance (shares) at Dec. 31, 2011	'	1,000	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income	258	'	'	258	'
Dividends declared	-184	'	'	-184	'
Other	-1	'	'	'	-1
Balance at Dec. 31, 2012	2,922	0	2,308	619	-5
Balance (shares) at Dec. 31, 2012	1,000	1,000	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income	145	'	'	145	'
Dividends declared	-178	'	'	-178	'
Other	1	'	'	'	1
Balance at Dec. 31, 2013	$2,890	$0	$2,308	$586	($4)
Balance (shares) at Dec. 31, 2013	1,000	1,000	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$145	$258	$133
Adjustments to reconcile net income to net cash flows from operating activities:	'	'	'
Depreciation and amortization	277	270	252
Deferred income taxes and amortization of investment tax credits	95	151	72
Allowance for equity funds	-8	-7	-8
Amortization of deferred energy	-54	-170	-105
Deferred energy	-105	112	109
Amortization of other regulatory assets	89	88	83
Other, net	90	-29	88
Changes in other operating assets and liabilities:	'	'	'
Accounts receivable and other assets	-12	3	-67
Inventories	10	-5	-6
Accounts payable and other liabilities	21	31	-24
Net cash flows from operating activities	548	702	527
Cash flows from investing activities:	'	'	'
Capital expenditures	-267	-288	-475
Proceeds from contribution in aid of construction and customer advances	34	43	87
Proceeds from sale of assets	14	0	32
Other, net	3	0	1
Net cash flows from investing activities	-216	-245	-355
Cash flows from financing activities:	'	'	'
Proceeds from issuance of long-term debt, net of costs	0	132	387
Repayments of long-term debt	-229	-270	-493
Settlement of interest rate lock	0	0	-15
Contribution	0	0	54
Dividends paid	-178	-184	-99
Net cash flows from financing activities	-407	-322	-166
Net change in cash and cash equivalents	-75	135	6
Cash and cash equivalents at beginning of period	201	66	60
Cash and cash equivalents at end of period	$126	$201	$66

Organization_and_Operations_No

Organization and Operations (Notes)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization and Operations	'
	Organization and Operations

	Nevada Power Company, together with its subsidiaries (collectively, the "Company"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of MidAmerican Energy Holdings Company ("MEHC"). MEHC is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

	On December 19, 2013, the merger contemplated by the Agreement and Plan of Merger dated May 29, 2013, among MEHC, Silver Merger Sub, Inc. ("Merger Sub"), MEHC's wholly owned subsidiary, and NV Energy, whereby Merger Sub was merged into NV Energy and NV Energy became an indirect wholly owned subsidiary of MEHC ("MEHC Merger") was completed.

	The transaction was approved by the boards of directors of both NV Energy and MEHC and the shareholders of NV Energy. MEHC received unconditional approval of the MEHC Merger from the Federal Energy Regulatory Commission ("FERC") on December 19, 2013 and the Federal Communications Commission on September 27, 2013. The United States Department of Justice and the Federal Trade Commission granted early termination of the mandatory waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976 on July 22, 2013. On December 17, 2013, the Public Utilities Commission of Nevada ("PUCN") approved the Joint Application filed by MEHC and NV Energy, subject to certain stipulations. The stipulations included, among others:


	•	A one-time bill credit to retail customers of the Company of $15 million credited to retail customers over one billing cycle beginning within 30 days of the close of the MEHC Merger.

	•	MEHC and NV Energy agreed to not seek recovery of the acquisition premium, transaction and transition costs associated with the MEHC Merger from customers.

	•	NV Energy agreed that it will base any rate case filed in 2014 by the Company with a requested change in revenue requirement on a return on common equity not to exceed 10%.

	•	The Company will not seek to collect lost revenues as described in section 704.9524 of the Nevada Administrative Code for calendar year 2013 in 2014 rates, and will not seek collection of lost revenues in excess of 50% of what the Company could otherwise request for calendar year 2014 in 2015 rates. NV Energy also agreed to work cooperatively with PUCN staff and the Nevada Bureau of Consumer Protection ("BCP") to develop a legislative or administrative alternative to the current mechanism that would retain the objective of encouraging investment in energy efficiency and that is acceptable to NV Energy, PUCN staff and the BCP. NV Energy and the BCP also agree to work in good faith to have a legislative or administrative alternative adopted.

	•	Normal rate case rules and procedures apply to costs and revenues, and any under or over earnings will accrue to the Company until the next rate case filing after 2014, subject to specified adjustments for intercompany charges from MEHC and its other subsidiaries as described in the PUCN Joint Application and the exclusion of the $15 million one-time bill credit from the test period. The commitment does not preclude parties from proposing any other adjustments to test year or certification period results.

Summary_of_Significant_Account

Summary of Significant Accounting Policies (Notes)	12 Months Ended
Summary of Significant Accounting Policies (Notes)	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies

	Basis of Consolidation and Presentation

	The Consolidated Financial Statements include the accounts of the Company and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.

	The impacts of acquisition accounting from the MEHC Merger were not reflected on the Consolidated Financial Statements of the Company.

	As a result of the MEHC Merger, the Company has elected to present its Consolidated Financial Statements and Notes to Consolidated Financial Statements for the current year and prior years similar to MEHC. Certain amounts from prior years have been reclassed to conform to the current period presentation. The change in format did not have an effect on net income, total assets, total shareholder's equity or cash flows from operations.
	Use of Estimates in Preparation of Financial Statements

	The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

	Accounting for the Effects of Certain Types of Regulation

	The Company prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Company defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

	The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Company's ability to recover its costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

	Fair Value Measurements

	As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

	Cash Equivalents and Restricted Cash and Investments

	Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets on the Consolidated Balance Sheets.

	Allowance for Doubtful Accounts

	Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The Company also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. As of December 31, 2013 and 2012, the allowance for doubtful accounts totaled $8 million and is included in accounts receivable, net on the Consolidated Balance Sheets.

	Derivatives

	The Company employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities; and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP.

	Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.

	For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.

	For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.

	Inventories

	Inventories consist mainly of materials and supplies totaling $54 million and $53 million as of December 31, 2013 and 2012, respectively, and fuel, which includes coal stocks, stored natural gas and fuel oil, totaling $19 million and $25 million as of December 31, 2013 and 2012, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the PUCN.

	Property, Plant and Equipment, Net

	General

	Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.

	Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Company to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

	Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

	Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. The Company's AFUDC rate used during both 2013 and 2012 was 8.09%. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.

	Asset Retirement Obligations

	The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

	Management's methodology to assess its legal obligation includes an inventory of assets by the Company's system and components and a review of rights of way and easements, regulatory orders, leases and federal, state and local environmental laws. Management identified legal obligations to retire generation plant assets specified in land leases for the Company's jointly-owned Navajo Generating Station and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl have met the requirements for an ARO.

Impairment

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. For all other assets, any resulting impairment loss is reflected on the Consolidated Statements of Operations.

Income Taxes

Berkshire Hathaway commenced including the Company in its United States federal income tax return on December 20, 2013 in connection with the MEHC Merger. Prior to December 20, 2013, the Company filed a consolidated United States federal income tax return with NV Energy. Consistent with established regulatory practice, the Company's provision for income taxes has been computed on a separate return basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company is required to pass on to its customers in Nevada are charged or credited directly to a regulatory asset or liability. As of December 31, 2013 and 2012, these amounts were recognized as regulatory assets of $165 million and $169 million, respectively, and regulatory liabilities of $4 million and $5 million, respectively, and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not of being realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.

Revenue Recognition

Revenue is recognized as electricity is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2013 and 2012, unbilled revenue was $103 million and $86 million, respectively, and is included in accounts receivable, net on the Consolidated Balance Sheets. Rates are established by regulators or contractual arrangements. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

The Company primarily buys energy and natural gas to satisfy its customer load requirements. Due to changes in retail customer load requirements, the Company may not take physical delivery of the energy or natural gas. The Company may sell the excess energy or natural gas to the wholesale market. In such instances, it is the Company's policy to record such sales net in cost of fuel, energy and capacity.

Unamortized Debt Premiums, Discounts and Financing Costs

Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Segment Information

The Company currently has one segment, which includes its regulated electric utility operations.

New Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-04, which amends FASB Accounting Standards Codification ("ASC") Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after December 15, 2013. The Company adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

In February 2013, the FASB issued ASU No. 2013-02, which amends FASB ASC Topic 220, "Comprehensive Income." The amendments in this guidance require an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required by GAAP that provide additional detail about those amounts. The Company adopted this guidance on January 1, 2013. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

In December 2011, the FASB issued ASU No. 2011-11, which amends FASB ASC Topic 210, "Balance Sheet." The amendments in this guidance require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally, this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the financial instruments and derivative instruments are not offset. In January 2013, the FASB issued ASU No. 2013-01, which also amends FASB ASC Topic 210 to clarify that the scope of ASU No. 2011-11 only applies to derivative instruments, repurchase agreements, reverse purchase agreements and securities borrowing and securities lending transactions that are either being offset or are subject to an enforceable master netting arrangement or similar agreement. The Company adopted the guidance on January 1, 2013. The adoption of the guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

MergerRelated_Activities_Notes

Merger-Related Activities (Notes)	12 Months Ended
Merger-Related Activities (Notes)	Dec. 31, 2013
Business Combinations [Abstract]	'
Merger-Related Activities	'
	Merger-Related Activities

	On December 17, 2013, the PUCN approved the Joint Application related to the MEHC Merger filed by MEHC and NV Energy, subject to certain stipulations. The stipulations included, among others, a one-time bill credit to retail customers of the Company of $15 million credited to retail customers over one billing cycle beginning within 30 days of the close of the MEHC Merger. The bill credit was included as a reduction to operating revenue on the Consolidated Statements of Operations for the year ended December 31, 2013.

	The Company incurred costs totaling $52 million related to the MEHC Merger, consisting of: (i) $15 million for amounts payable under NV Energy's change in control policy; (ii) $18 million for accelerated vesting and stock compensation under NV Energy's long-term incentive plan; (iii) $15 million for investment banker fees paid by NV Energy and (iv) $4 million for legal and other expenses. The costs were included in merger-related expenses on the Consolidated Statements of Operations for the year ended December 31, 2013.

Property_Plant_and_Equipment_N

Property, Plant and Equipment, Net (Notes)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment, Net [Abstract]	'
Property, Plant and Equipment, Net	'
	Property, Plant and Equipment, Net

	Property, plant and equipment, net consists of the following as of December 31 (in millions):


		2013			2012
	Utility plant in-service:
	Generation	$	3,789		$	3,706

	Distribution	2,936			2,885

	Transmission	1,743			1,189

	General intangible plant	645			583

	Utility plant in-service	9,113			8,363

	Accumulated depreciation and amortization	(2,217		)	(2,035		)
	Utility plant in-service, net	6,896			6,328

	Other non-regulated, net of accumulated depreciation and amortization	3			16

		6,899			6,344

	Construction work-in-progress	93			568

	Property, plant and equipment, net	$	6,992		$	6,912


	Almost all of the Company's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. The Company's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the average depreciable property balances was 3.26%, 3.22% and 3.04% during 2013, 2012 and 2011, respectively. The Company is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate case filings.

	Construction work-in-progress is related to the construction of regulated assets.

	Impairment of Regulated Assets Not In Rates

	The Company recorded an impairment charge of $31 million in operating and maintenance expense on the Consolidated Statements of Operations for the year ended December 31, 2013 related to the recovery of certain assets not currently in rates.

	Sale of Telecommunication Towers

	In August 2011, the Company completed the sale of 37 telecommunication towers to Global Tower Partners, LLC. Cash proceeds from the sale were $32 million with the gain on sale deferred subject to the final accounting approval by the PUCN.

	In March 2012, the Company filed a petition with the PUCN to obtain a declaratory order and the accounting guidance necessary to establish a regulatory account for the gain on sale of the Company's telecommunication towers to Global Tower Partners, LLC. In July 2012, the PUCN approved a stipulation between the Company, the BCP, and PUCN staff that provides for an allocation of $27 million of the $32 million gain on sale to the ratepayers. The amortization of the gain will coincide with the rate effective date of the Company's next general rate case, which is mandated in 2015. The Company recorded $6 million, including an adjustment to previously recorded carrying charges, to other, net on the Consolidated Statements of Operations for the remaining balance of the gain on sale for the year ended December 31, 2012.

Jointly_Owned_Utility_Faciliti

Jointly Owned Utility Facilities (Notes)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Facilities [Abstract]	'
Jointly Owned Utility Facilities	'
	Jointly Owned Utility Facilities

	Under joint facility ownership agreements, the Company, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. The Company accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities. The amounts shown in the table below represent the Company's share in each jointly owned facility as of December 31, 2013 (dollars in millions):


							Construction
		Company	Facility In		Accumulated		Work-in-
		Share	Service		Depreciation		Progress

	Silverhawk Generating Station	75%	$	242	$	57	$	3

	Navajo Generating Station	11	198		132		3

	ON Line Transmission Line(1)	24	140		—		—

	Other Transmission Facilities	Various	68		27		—

	Total		$	648	$	216	$	6



	-1	ON Line was placed in-service December 2013. The Company and Sierra Pacific entered into a long-term transmission use agreement with Great Basin Transmission South, LLC's 75% interest in ON Line. Refer to Note 9 for additional information.

Regulatory_Matters_Notes

Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Matters	'
	Regulatory Matters

	Regulatory assets represent costs that are expected to be recovered in future rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


		Weighted
		Average
		Remaining Life		2013			2012

	Deferred income taxes(1)	28 years		$	165		$	169

	Deferred excess energy costs	2 years		159			87

	Merger costs from 1999 merger	29 years		155			162

	Abandoned projects	7 years		115			42

	Asset retirement obligations	4 years		98			58

	Employee benefit plans(2)	13 years		83			137

	Demand side resources	3 years		70			123

	Legacy meters	7 years		65			61

	Deferred operating costs	29 years		63			65

	Unrealized loss on regulated derivative contracts	5 years		47			—

	Other	Various		118			124

	Total regulatory assets			$	1,138		$	1,028


	Reflected as:
	Current assets			$	81		$	—

	Noncurrent assets			1,057			1,028

	Total regulatory assets			$	1,138		$	1,028



	-1	Amounts primarily represent income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.

	-2	Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

	The Company had regulatory assets not earning a return on investment of $598 million and $459 million as of December 31, 2013 and 2012, respectively, that primarily related to deferred income taxes, 1999 merger costs, a portion of deferred excess energy costs and unrealized loss on regulated derivative contracts.

	Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


		Weighted
		Average
		Remaining Life		2013			2012

	Cost of removal(1)	37 years		$	273		$	252

	Energy efficiency program	1 year		57			37

	Renewable energy program	1 year		18			—

	Deferred income taxes	19 years		4			5

Deferred energy over collected	1 year		—			86

Other	Various		34			29

Total regulatory liabilities			$	386		$	409


Reflected as:
Current liabilities			$	74		$	86

Noncurrent liabilities			312			323

Total regulatory liabilities			$	386		$	409



-1	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN.

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and is included in the table above as deferred excess energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy over collected. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Energy Efficiency Implementation Rates and Energy Efficiency Program Rates

In July 2010, regulations were adopted by the PUCN that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN through energy efficiency implementation rates ("EEIR"). As a result, the Company files annually in March to adjust energy efficiency program rates and EEIR for over- or under-collected balances, which are effective in October of the same year.

In March 2013, the Company filed applications with the PUCN for the twelve-month period ended December 31, 2012 to reset EEIR elements. In September 2013, the PUCN issued an order indicating that EEIR revenue should not contribute to the Company earning more than its authorized rate of return. As the Company earned in excess of its authorized rate of return in 2012, the PUCN disallowed approximately $11 million in EEIR revenue (including carrying charges) and the Company recorded a charge to operating and maintenance expense on the Consolidated Statements of Operations for the year ended December 31, 2013.

The PUCN's final order approving the MEHC Merger stipulated that the Company, will not seek recovery of any lost revenue for calendar year 2013 and, for calendar year 2014, in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. As a result, for the year ended December 31, 2013, the Company has not recorded revenue for EEIR and has recorded a regulatory liability of $12 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets. On February 28, 2014, the Company filed an application with the PUCN to reset EEIR and energy efficiency program rates. Pursuant to the stipulation, the Company established credits to return EEIR revenue collected in the 2013 calendar year. To effect the merger stipulation, the Company proposed to suspend collection of the EEIR on October 1, 2014, and defer implementation of a new EEIR until January 1, 2015.

FERC Matters

2012 FERC Transmission Rate Case

In October 2012, the Company filed an application with the FERC to revise transmission and ancillary service rates that were last set in 2003. In December 2012, the 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. On November 27, 2013, the Company filed an unopposed settlement agreement resolving all issues with the FERC, for approval of rates effective June 1, 2013. The FERC approved the settlement on February 21, 2014. The rate changes under the terms of the settlement agreement result in an overall annual revenue increase of $5 million.

2013 FERC Transmission Rate Case

In May 2013, the Company, along with Sierra Pacific, filed an application with the FERC to establish single system transmission and ancillary service rates. The combined filing requested incremental rate relief of $17 million annually to be effective January 1, 2014. On August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to refund, and set the case for hearing or settlement discussions. On January 1, 2014, the Company implemented the filed rates in this case subject to refund as set forth in FERC's order. At this time management is unable to determine the final revenue impact of the case.

Risk_Management_Notes

Risk Management (Notes)	12 Months Ended
Risk Management (Notes)	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Risk Management	'
	Risk Management and Hedging Activities

	The Company is exposed to the impact of market fluctuations in electricity, natural gas, coal, and other commodity prices and interest rates primarily through the Company's obligation to serve retail customer load in its regulated service territory. The Company's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power are recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. The Company does not engage in proprietary trading activities.

	The Company has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production, generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

	There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Notes 2, 6 and 10 for additional information on derivative contracts.

	Derivative Contract Volumes

	Net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values as of December 31, 2013 were 118 million decatherms of commodity volume natural gas purchases and 4 million in megawatt hour commodity volume electric sales.

	Collateral and Contingent Features

	In accordance with industry practice, certain wholesale derivative contracts contain provisions that require the Company to maintain specific credit ratings from one or more of the major credit rating agencies on its unsecured debt. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand adequate assurance in the event of a material adverse change in the Company's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2013, credit ratings from the three recognized credit rating agencies were investment grade.

	The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features were immaterial. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

	Credit Risk

	The Company extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.

	The Company analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Company enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Company exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Credit_Facility_Notes

Credit Facility (Notes)	12 Months Ended
Credit Facility (Notes)	Dec. 31, 2013
Line of Credit Facility [Abstract]	'
Short-term Debt and Credit Facilities	'
	Credit Facility

	The Company's $500 million revolving credit facility expires in 2017, is for general corporate purposes and provides for the issuances of letters of credits. As of December 31, 2013 and 2012, the Company had no drawings outstanding and letters of credit issued were $- million and $3 million, respectively. Amounts due under the Company's credit facility are collateralized by the Company's general and refunding mortgage bonds. The rate for outstanding loans under the Company's credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the London Interbank Offered Rate ("LIBOR") Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon the Company's credit rating by Standard & Poor's and Moody's Investors Services. As of December 31, 2013, the Company's applicable base rate margin is 0.125% and the LIBOR rate margin is 1.125%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

LongTerm_Debt_Notes

Long-Term Debt (Notes)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt

	The Company's long-term debt consists of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):


		Par Value			2013		2012
	General and Refunding Mortgage Securities:
	7.375% Series U, due 2014	$	—		$	—	$	125

	5.875% Series L, due 2015	250			250		250

	5.950% Series M, due 2016	210			210		210

	6.500% Series O, due 2018	325			324		324

	6.500% Series S, due 2018	500			499		499

	7.125% Series V, due 2019	500			501		501

	6.650% Series N, due 2036	370			363		363

	6.750% Series R, due 2037	350			349		349

	5.375% Series X, due 2040	250			249		249

	5.450% Series Y, due 2041	250			250		250

	Variable-rate series (2013-0.454% to 0.459%, 2012-0.575% to 0.626%):
	Industrial Development Refunding Revenue Bonds 2000A, due 2020	—			—		98

	Pollution Control Revenue Bonds Series 2006A, due 2032	38			38		38

	Pollution Control Revenue Bonds Series 2006, due 2036	38			38		38

	Capital and financial lease obligations - 3.01% to 11.60%, due through 2054	506			506		43

	Total long-term debt	$	3,587		$	3,577	$	3,337


	Reflected as:
	Current liabilities				$	22	$	106

	Noncurrent liabilities				3,555		3,231

	Total long-term debt				$	3,577	$	3,337


	The consummation of the MEHC Merger also triggered mandatory redemption requirements under financing agreements of the
	Company. As a result, the Company offered to purchase $3.0 billion of debt at 101% of par. Debt with a par value totaling $5 million was tendered in January 2014 and paid with cash on hand. The tender offer expired in January 2014.

	In November 2013, the Company issued a notice of redemption to the bondholders for its $125 million, 7.375% Series U General and Refunding Mortgage Securities. In December 2013, the Company redeemed the aggregate principal amount outstanding of $125 million at 100.7% of the principal amount plus accrued interest with the use of cash on hand.

	In July 2013, the Company issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, the Company redeemed the aggregate principal amount outstanding of $98 million at 100% of the principal amount plus accrued interest with the use of cash on hand.

	In April 2012, the Company used $120 million from its revolving credit facility along with $10 million of cash on hand to pay for the maturity of its 6.5% General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million.

	Annual Payment on Long-Term Debt

	The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 2014 and thereafter, excluding unamortized premiums and discounts, are as follows (in millions):


	2014		$	22

2015		261

2016		222

2017		14

2018		839

2019 and thereafter		2,229

Total		$	3,587


Utility plant of $3.7 billion is subject to the liens of the Company's indentures under which its respective General and Refunding Mortgage Securities are issued.

Capital and Financial Lease Commitments


•	In 1984, the Company entered into a 30-year capital lease for the Pearson Building with five, five-year renewal options beginning in year 2015. In February 2010, the Company amended this capital lease agreement to include the lease of the adjoining parking lot and to exercise, three of the five-year renewal options beginning in year 2015. There remain two additional renewal options which could extend the lease an additional ten years. Capital assets of $39 million were included in property, plant and equipment, net as of December 31, 2013.

•	In 2007, the Company entered into a 20-year lease, with three 10-year renewal options, to occupy land and building for its Beltway Complex operations center in southern Nevada. The Company accounts for the building portion of the lease as a capital lease and the land portion of the lease as an operating lease. The Company transferred operations to the facilities in June 2009. Capital assets of $10 million were included in property, plant and equipment, net as of December 31, 2013.

•	The Company has long-term energy purchase contracts which qualify as capital leases. The leases were entered into between the years 1989 and 1990 and firm operation occurred through 1993. The terms of the leases are for 30 years and expire between the years 2022-2023. Capital assets of $71 million were included in property, plant and equipment, net as of December 31, 2013.

•	The Company has master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. Lease terms average seven years under the master lease agreement.

•	The ON Line transmission line was placed in-service on December 31, 2013. The Company and Sierra Pacific have entered into a transmission use agreement with Great Basin Transmission South, LLC's 75% interest in ON Line. The Company and Sierra Pacific own the remaining 25% interest. Refer to Note 5 for additional information. The Company's and Sierra Pacific's share of the long-term transmission use agreement and ownership interest is split at 95% and 5%, respectively. The term is for 41 years with the agreement ending December 31, 2054. Payments began on January 31, 2014.

Future cash payments for capital and financial leases as of December 31, 2013, were as follows (in millions):


2014		$	74

2015		74

2016		73

2017		74

2018		73

2019 and thereafter		1,049

Total minimum lease payments		1,417

Less:
Executory costs		(166		)
Amounts representing interest		(745		)
Present value of net minimum lease payments		$	506

Fair_Value_Measurements_Notes

Fair Value Measurements (Notes)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, investments held in Rabbi trusts, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities, principally related to derivative contracts, that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

•

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•

Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

As of December 31, 2013, the Company has derivative contracts stated at estimated fair value of $9 million, included in customer deposits and other, and $38 million, included in other long-term liabilities. The Company's commodity derivatives are not designated as hedging contracts as they are included in regulated rates, and as such, a regulatory asset of $47 million was recorded related to the commodity derivative contracts.

Forward contracts are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact of the Company's nonperformance risk on its liabilities, which as of December 31, 2013, had an immaterial impact to the fair value of its derivative instruments. As such, the Company considers its derivative contracts to be valued using Level 3 inputs.

The Company's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):

2013

2012

Carrying

Fair

Carrying

Fair

Value

Long-term debt

3,071

3,596

3,294

4,074

Other_Net_Notes

Other, Net (Notes)	12 Months Ended
	Dec. 31, 2013
Other Nonoperating Income (Expense) [Abstract]	'
Other, Net	'
	Other, Net

	Other, net as shown on the Consolidated Statements of Operations for the years ended December 31 consists of the following (in millions):


		2013			2012			2011

	Interest and dividend income	$	5		$	4		$	3

	Donations	—			(2		)	(5		)

	Interest expense on regulatory items	(2		)	(7		)	1

	Other	2			2			(25		)

	Total other, net	$	5		$	(3	)	$	(26	)

Income_Taxes_Notes

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes

	Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):


		2013				2012				2011

	Current – Federal	$	(1	)		$	(12	)		$	(1	)
	Deferred – Federal	96				151				73

	Investment tax credits	(1		)		(1		)		(1		)
	Total income tax expense	$	94			$	138			$	71


	A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:


		2013			2012			2011

	Federal statutory income tax rate	35	%		35	%		35	%
	Non-deductible MEHC Merger related expenses	3			—			—

	Effects of ratemaking	1			1			1

	Other	—			(1	)		(1	)

	Effective income tax rate	39	%		35	%		35	%

	The net deferred income tax liability consists of the following as of December 31 (in millions):


		2013				2012
	Deferred income tax assets:
	Federal net operating loss and credit carryforwards	$	265			$	264

	Capital and financial leases	177				15

	Employee benefits	11				35

	Regulatory liabilities	4				5

	Other	85				51

	Total deferred income tax assets	542				370

	Valuation allowance	(2		)		(1		)
	Total deferred income tax assets, net	540				369


	Deferred income tax liabilities:
	Property-related items	(1,145		)		(1,071		)
	Regulatory assets	(314		)		(284		)
	Capital and financial leases	(189		)		(14		)
	Other	(38		)		(53		)
	Total deferred income tax liabilities	(1,686		)		(1,422		)
	Net deferred income tax liability	$	(1,146	)		$	(1,053	)

	Reflected as:
	Deferred income taxes - current	$	152			$	49

	Deferred income taxes - long-term	(1,298		)		(1,102		)
	Net deferred income tax liability	$	(1,146	)		$	(1,053	)

The following table provides the Company's federal net operating loss and tax credit carryforwards and expiration dates as of December 31, 2013 (in millions):


Net operating loss carryforwards	$	726

Deferred income taxes on federal net operating loss carryforwards	$	254

Expiration dates	2029-2033

Other tax credits	$	11

Expiration dates	2014-2033

The United States federal jurisdiction is the only significant income tax jurisdiction for NV Energy. In July 2012, the United States Internal Revenue Service and the Joint Committee on Taxation concluded their examination of NV Energy with respect to its United States federal income tax returns for December 31, 2005 through December 31, 2008.

A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):


	2013				2012

Beginning balance	$	4			$	24

Additions for tax positions of prior years	—				1

Reductions for tax positions of prior years	(1		)		(21		)
Ending balance	$	3			$	4


As of December 31, 2013 and 2012, the Company had unrecognized tax benefits totaling $2 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.

RelatedParty_Transactions_Note

Related-Party Transactions (Notes)	12 Months Ended
Related-Party Transactions (Notes)	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions Disclosure	'
	Related Party Transactions

	Kern River Gas Transmission Company, an indirect subsidiary of MEHC, provided natural gas transportation and other services to the Company of $68 million, $66 million and $50 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013 and 2012, the Company's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $5 million.

	As of December 31, 2013, included in accounts receivable on the Consolidated Balance Sheets was $2 million in amounts due from MEHC for merger related reimbursements.

	The Company provided electricity and other services to PacifiCorp, an indirect subsidiary of MEHC, of $3 million, $7 million and $3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Receivables associated with these services were $- million and $1 million as of December 31, 2013 and 2012, respectively. PacifiCorp provided electricity and the sale of renewable energy credits to the Company of $2 million, $62 million and $54 million for the years ended December 31, 2013, 2012 and 2011, respectively. Payables associated with these transactions were $- million and $7 million as of December 31, 2013 and 2012, respectively.

	The Company provided electricity to Sierra Pacific of $36 million, $20 million and $22 million for the years ended December 31, 2013, 2012 and 2011, respectively. Receivables associated with these transactions were $3 million and $4 million as of December 31, 2013 and 2012, respectively. The Company purchased electricity from Sierra Pacific of $1 million, $1 million and $2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

	The Company incurs intercompany administrative and shared facility costs between NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. The Company provided services to NV Energy of $- million, $1 million, and $1 million for the years ending December 31, 2013, 2012 and 2011, respectively. NV Energy provided services to the Company $45 million, $27 million and $23 million for the years ending December 31, 2013, 2012 and 2011, respectively. The Company provided services to Sierra Pacific of $24 million, $20 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively. Sierra Pacific provided services to the Company of $22 million, $22 million and $22 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013 and 2012, the Company's Consolidated Balance Sheets included amounts due to NV Energy of $60 million and $39 million. As of December 31, 2013, the Company's Consolidated Balance Sheets included receivables due from Sierra Pacific of $6 million and as of December 31, 2012 included accounts payable to Sierra Pacific of $3 million.

	Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of the Company and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.

Retirement_Plan_and_Postretire

Retirement Plan and Postretirement Benefits (Notes)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Retirement Plan and Postretirement Benefits	'
	Retirement Plan and Postretirement Benefits

	The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non-Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the Company. The Company did not make any contributions to the Qualified Pension Plan, Non-Qualified Pension Plans or Other Postretirement Plans for the years ended December 31, 2013 and 2012. The Company contributed $15 million to the Qualified Pension Plan and did not make any contributions to the Non-Qualified Pension Plans or Other Postretirement Plans for the year ended December 31, 2011. Amounts attributable to the Company were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in AOCI.

	Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31(in millions):


		2013			2012
	Qualified Pension Plan:
	Other assets	$	13		$	—

	Other long-term liabilities	—			(21		)


	Non-Qualified Pension Plans:
	Customer deposits and other	(4		)	—

	Other long-term liabilities	(8		)	(13		)

	Other Postretirement Plans -
	Other long-term liabilities	(7		)	(15		)

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Notes)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations

	The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including plan revisions, inflation and changes in the amount and timing of the expected work.

	The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $273 million and $252 million as of December 31, 2013 and 2012, respectively.

	The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):


		2013		2012

	Evaporative ponds and dry ash landfills	$	84	$	46

	Asbestos	4		3

	Other	12		11

	Total asset retirement obligations	$	100	$	60


	The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):


		2013		2012

	Beginning balance	$	60	$	61

	Accretion	3		3

	Change in estimated costs	37		(4		)

	Ending balance	$	100	$	60


	In 2008, the Company signed an administrative order of consent as owner and operator of Reid Gardner Generating Station units 1, 2 and 3 and as co-owner and operating agent of unit 4. Based on the administrative order of consent, the Company recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between the Company and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station unit 4, the Company and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent. The 2013 change in estimated costs was primarily related to refinement of expected remediation costs at the Reid Gardner Generating Station.

	Certain of the Company's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, the Company is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.

Commitments_and_Contingencies_

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies

	Commitments

	The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2013 are as follows (in millions):


												2019 and
		2014		2015		2016		2017		2018		Thereafter		Total

	Purchased power	$	397	$	400	$	401	$	401	$	347	$	3,461	$	5,407

	Purchased power - not commercially operable	64		72		91		105		106		2,432		2,870

	Coal and natural gas	395		169		48		44		46		47		749

	Transportation	70		81		69		66		51		583		920

	Long-term service agreements	15		15		15		13		10		28		96

	Operating leases	7		6		5		4		4		92		118

	Total commitments	$	948	$	743	$	629	$	633	$	564	$	6,643	$	10,160


	Purchased Power

	The Company has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2014 to 2038. While the Company is not required to make payment if power is not delivered under these contracts, estimated future payments are included in the tables above. Purchased power includes contracts which meet the definition of a lease. The Company's rent expense for purchase power contracts which met the lease criteria for 2013, 2012 and 2011 were $400 million, $353 million and $296 million, respectively, and are recorded as cost of fuel, energy and capacity on the Consolidated Statements of Operations.

	Purchased Power - Not Commercially Operable

	The Company has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.

	Coal and Natural Gas

	The Company has several long-term contracts for the purchase of coal and natural gas. The expiration of these contracts range from 2014 to 2019.

	Transportation

	The Company has several long-term contracts for the transport of coal and natural gas. The expiration of these transportation contracts range from 2014 to 2031.

	Long-Term Service Agreements

	The Company has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The expiration of these service agreements range from 2018 to 2023. The Company entered into long- term service agreements for maintenance on generation units in March 2014 expiring in 2026 and 2028. Payments under the agreements are $7 million, $8 million, $7 million, $7 million, $5 million and $38 million for the years ended December 31, 2014, 2015, 2016, 2017, 2018 and thereafter, respectively.

	Operating Leases

	The Company has various non-cancelable operating leases primarily for building, land and equipment. Contract expiration dates range from 2014 to 2103. Rent expense on non-cancelable operating leases totaled $9 million for 2013, $10 million for 2012 and $11 million for 2011.

	Environmental Laws and Regulations

	The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

	In June 2013, the Nevada State Legislature passed Senate Bill No. 123, which included, in significant part:


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

	•	Replacement of such coal plants by issuing requests for proposals for 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 additional electric generating capacity; and

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

In February 2014, the PUCN issued a final order approving draft regulations, subject to review by a Nevada Legislative commission and which must be filed with the Secretary of State before the regulations become effective. The new regulations require the Company to file its initial emissions reduction and capacity replacement plan on or before May 1, 2014.

Reid Gardner Generation Station

In October 2011, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Reid Gardner Generating Station located near Moapa, Nevada. The Environmental Protection Agency'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 Environmental Protection Agency relating to the plant. The Company completed its responses to the Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this information request.

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC ("NLI") purchased from the United States through the Bureau of Land Management 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land is traversed by a 500 kilovolt transmission line owned by the Company and sited pursuant to a pre-existing right-of-way grant from the Bureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, if it did, the amount owed to NLI under the right-of-way grant. NLI eventually "terminated" the right-of-way grant and brought claims against the Company for breach of contract, inverse condemnation and trespass. The Company 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 ("Eighth District Court"). In September 2013, the Eighth District Court awarded NLI $1 million for unpaid rent and $5 million for inverse condemnation, plus interest and attorneys' fees, bringing the total judgment to $12 million, which the Company recognized as of December 31, 2013. The Eighth District Court also found the Company was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor. The Company has appealed to the Nevada Supreme Court. Management cannot assess or predict the outcome of the case at this time.

Sierra Club and Moapa Band of Paiute Indians

In August 2013, the Sierra Club and Moapa Band of Paiute Indians filed a complaint in federal district court in Nevada against the Company and CWDR, alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to the environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the Resource Conservation and Recovery Act. The complaint also alleges that the Reid Gardner Generating Station is engaged in the unlawful discharge of pollutants in violation of the Clean Water Act. The notice was issued pursuant to the citizen suit provisions of the Resource Conservation and Recovery Act and the Clean Water Act. CDWR was named as a co-defendant in the litigation due to its prior co-ownership in Reid Gardner Generating Station unit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. The Company answered the complaint and intends to vigorously defend the suit. Given the stage of the proceeding, management cannot predict the impact to the Company, or estimate the range of loss.

Supplemental_Cash_Flow_Disclos

Supplemental Cash Flow Disclosures (Notes)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]	'
Supplemental Cash Flow Disclosures	'
	Supplemental Cash Flow Disclosures

	The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):


		2013		2012		2011

	Supplemental disclosure of cash flow information -
	Interest paid, net of amounts capitalized	$	209	$	208	$	219


	Supplemental disclosure of non-cash investing and financing transactions:
	Accruals related to property, plant and equipment additions	$	25	$	150	$	176

	ON Line transmission use financial lease obligation	$	419	$	—	$	—

Unaudited_Quarterly_Operating_

Unaudited Quarterly Operating Results (Notes)	12 Months Ended
	Dec. 31, 2013
Unaudited Quarterly Operating Results [Abstract]	'
Unaudited Quarterly Operating Results	'
	Unaudited Quarterly Operating Results (in millions)



		Three-Month Periods Ended
		31-Mar-13			30-Jun-13		30-Sep-13		31-Dec-13

	Operating revenue	$	372		$	537	$	786	$	397

	Operating income	58			141		305		(69		)

	Net income	5			59		164		(83		)



		Three-Month Periods Ended
		31-Mar-12			30-Jun-12		30-Sep-12		31-Dec-12

	Operating revenue	$	396		$	553	$	802	$	394

	Operating income	53			147		346		56

	Net income	(1		)	62		195		2

Schedule_II_Consolidated_Valua

Schedule II Consolidated Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2013

Schedule II Consolidated Valuation and Qualifying Accounts [Abstract]

Schedule II Consolidated Valuation and Qualifying Accounts

NEVADA POWER COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

FOR THE THREE YEARS ENDED DECEMBER 31, 2013

(Amounts in millions)

Column B

Column C

Column E

Balance at

Charged

Balance

Column A

Beginning

Column D

at End

Description

of Year

Income

Deductions

of Year

Reserve for uncollectible accounts receivable:

Year ended 2013

(15

)

Year ended 2012

(14

)

Year ended 2011

(33

)

The notes to the consolidated financial statements are an integral part of this financial statement schedule.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of Consolidation and Presentation	'
	Basis of Consolidation and Presentation

	The Consolidated Financial Statements include the accounts of the Company and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.

	The impacts of acquisition accounting from the MEHC Merger were not reflected on the Consolidated Financial Statements of the Company.

	As a result of the MEHC Merger, the Company has elected to present its Consolidated Financial Statements and Notes to Consolidated Financial Statements for the current year and prior years similar to MEHC. Certain amounts from prior years have been reclassed to conform to the current period presentation. The change in format did not have an effect on net income, total assets, total shareholder's equity or cash flows from operations.
Use of Estimates in Preparation of Financial Statements	'
	Use of Estimates in Preparation of Financial Statements

	The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation	'
	Accounting for the Effects of Certain Types of Regulation

	The Company prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Company defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

	The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Company's ability to recover its costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements	'
	Fair Value Measurements

	As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments	'
	Cash Equivalents and Restricted Cash and Investments

	Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets on the Consolidated Balance Sheets.
Allowance for Doubtful Accounts	'
	Allowance for Doubtful Accounts

	Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The Company also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. As of December 31, 2013 and 2012, the allowance for doubtful accounts totaled $8 million and is included in accounts receivable, net on the Consolidated Balance Sheets.
Derivatives	'
	Derivatives

	The Company employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities; and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP.

	Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.

	For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.

	For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.
Inventories	'
	Inventories

	Inventories consist mainly of materials and supplies totaling $54 million and $53 million as of December 31, 2013 and 2012, respectively, and fuel, which includes coal stocks, stored natural gas and fuel oil, totaling $19 million and $25 million as of December 31, 2013 and 2012, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the PUCN.
Property, Plant and Equipment, Net - General	'
	Property, Plant and Equipment, Net

	General

	Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.

	Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Company to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

	Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

	Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. The Company's AFUDC rate used during both 2013 and 2012 was 8.09%. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.
Property, Plant and Equipment, Net - Asset Retirement Obligations	'
	Asset Retirement Obligations

	The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

	Management's methodology to assess its legal obligation includes an inventory of assets by the Company's system and components and a review of rights of way and easements, regulatory orders, leases and federal, state and local environmental laws. Management identified legal obligations to retire generation plant assets specified in land leases for the Company's jointly-owned Navajo Generating Station and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl have met the requirements for an ARO.
Property, Plant and Equipment, Net - Impairment	'
	Impairment

	The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. For all other assets, any resulting impairment loss is reflected on the Consolidated Statements of Operations.
Income Taxes	'
	Income Taxes

	Berkshire Hathaway commenced including the Company in its United States federal income tax return on December 20, 2013 in connection with the MEHC Merger. Prior to December 20, 2013, the Company filed a consolidated United States federal income tax return with NV Energy. Consistent with established regulatory practice, the Company's provision for income taxes has been computed on a separate return basis.

	Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company is required to pass on to its customers in Nevada are charged or credited directly to a regulatory asset or liability. As of December 31, 2013 and 2012, these amounts were recognized as regulatory assets of $165 million and $169 million, respectively, and regulatory liabilities of $4 million and $5 million, respectively, and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
Uncertain income tax positions	'
Uncertain income tax positions	In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not of being realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition	'
	Revenue Recognition

	Revenue is recognized as electricity is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2013 and 2012, unbilled revenue was $103 million and $86 million, respectively, and is included in accounts receivable, net on the Consolidated Balance Sheets. Rates are established by regulators or contractual arrangements. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

	The Company primarily buys energy and natural gas to satisfy its customer load requirements. Due to changes in retail customer load requirements, the Company may not take physical delivery of the energy or natural gas. The Company may sell the excess energy or natural gas to the wholesale market. In such instances, it is the Company's policy to record such sales net in cost of fuel, energy and capacity.
Unamortized Debt Premiums, Discounts and Financing Costs	'
	Unamortized Debt Premiums, Discounts and Financing Costs

	Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Segment Information	'
	Segment Information

	The Company currently has one segment, which includes its regulated electric utility operations.
New Accounting Pronouncements	'
	New Accounting Pronouncements

	In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-04, which amends FASB Accounting Standards Codification ("ASC") Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after December 15, 2013. The Company adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

	In February 2013, the FASB issued ASU No. 2013-02, which amends FASB ASC Topic 220, "Comprehensive Income." The amendments in this guidance require an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required by GAAP that provide additional detail about those amounts. The Company adopted this guidance on January 1, 2013. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

	In December 2011, the FASB issued ASU No. 2011-11, which amends FASB ASC Topic 210, "Balance Sheet." The amendments in this guidance require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally, this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the financial instruments and derivative instruments are not offset. In January 2013, the FASB issued ASU No. 2013-01, which also amends FASB ASC Topic 210 to clarify that the scope of ASU No. 2011-11 only applies to derivative instruments, repurchase agreements, reverse purchase agreements and securities borrowing and securities lending transactions that are either being offset or are subject to an enforceable master netting arrangement or similar agreement. The Company adopted the guidance on January 1, 2013. The adoption of the guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

Property_Plant_and_Equipment_N1

Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment, Net [Abstract]	'
Property, Plant, and Equipment, Net	'
	Property, plant and equipment, net consists of the following as of December 31 (in millions):


		2013			2012
	Utility plant in-service:
	Generation	$	3,789		$	3,706

	Distribution	2,936			2,885

	Transmission	1,743			1,189

	General intangible plant	645			583

	Utility plant in-service	9,113			8,363

	Accumulated depreciation and amortization	(2,217		)	(2,035		)
	Utility plant in-service, net	6,896			6,328

	Other non-regulated, net of accumulated depreciation and amortization	3			16

		6,899			6,344

	Construction work-in-progress	93			568

	Property, plant and equipment, net	$	6,992		$	6,912

Jointly_Owned_Utility_Faciliti1

Jointly Owned Utility Facilities (Tables)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]	'
Jointly Owned Utility Facilities	'
	The amounts shown in the table below represent the Company's share in each jointly owned facility as of December 31, 2013 (dollars in millions):


							Construction
		Company	Facility In		Accumulated		Work-in-
		Share	Service		Depreciation		Progress

	Silverhawk Generating Station	75%	$	242	$	57	$	3

	Navajo Generating Station	11	198		132		3

	ON Line Transmission Line(1)	24	140		—		—

	Other Transmission Facilities	Various	68		27		—

	Total		$	648	$	216	$	6



	-1	ON Line was placed in-service December 2013. The Company and Sierra Pacific entered into a long-term transmission use agreement with Great Basin Transmission South, LLC's 75% interest in ON Line. Refer to Note 9 for additional information.

Regulatory_Matters_Tables

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Assets	'
	Regulatory assets represent costs that are expected to be recovered in future rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


		Weighted
		Average
		Remaining Life	2013		2012

	Deferred income taxes(1)	28 years	$	165	$	169

	Deferred excess energy costs	2 years	159		87

	Merger costs from 1999 merger	29 years	155		162

	Abandoned projects	7 years	115		42

	Asset retirement obligations	4 years	98		58

	Employee benefit plans(2)	13 years	83		137

	Demand side resources	3 years	70		123

	Legacy meters	7 years	65		61

	Deferred operating costs	29 years	63		65

	Unrealized loss on regulated derivative contracts	5 years	47		—

	Other	Various	118		124

	Total regulatory assets		$	1,138	$	1,028


	Reflected as:
	Current assets		$	81	$	—

	Noncurrent assets		1,057		1,028

	Total regulatory assets		$	1,138	$	1,028



	-1	Amounts primarily represent income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.

	-2	Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
Regulatory Liabilities	'
	Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


		Weighted
		Average
		Remaining Life	2013		2012

	Cost of removal(1)	37 years	$	273	$	252

	Energy efficiency program	1 year	57		37

	Renewable energy program	1 year	18		—

	Deferred income taxes	19 years	4		5

	Deferred energy over collected	1 year	—		86

	Other	Various	34		29

	Total regulatory liabilities		$	386	$	409


	Reflected as:
	Current liabilities		$	74	$	86

	Noncurrent liabilities		312		323

	Total regulatory liabilities		$	386	$	409



	-1	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-term Debt	'
	The Company's long-term debt consists of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):


		Par Value				2013		2012
	General and Refunding Mortgage Securities:
	7.375% Series U, due 2014	$	—			$	—	$	125

	5.875% Series L, due 2015	250				250		250

	5.950% Series M, due 2016	210				210		210

	6.500% Series O, due 2018	325				324		324

	6.500% Series S, due 2018	500				499		499

	7.125% Series V, due 2019	500				501		501

	6.650% Series N, due 2036	370				363		363

	6.750% Series R, due 2037	350				349		349

	5.375% Series X, due 2040	250				249		249

	5.450% Series Y, due 2041	250				250		250

	Variable-rate series (2013-0.454% to 0.459%, 2012-0.575% to 0.626%):
	Industrial Development Refunding Revenue Bonds 2000A, due 2020	—				—		98

	Pollution Control Revenue Bonds Series 2006A, due 2032	38				38		38

	Pollution Control Revenue Bonds Series 2006, due 2036	38				38		38

	Capital and financial lease obligations - 3.01% to 11.60%, due through 2054	506				506		43

	Total long-term debt	$	3,587			$	3,577	$	3,337


	Reflected as:
	Current liabilities					$	22	$	106

	Noncurrent liabilities					3,555		3,231

	Total long-term debt					$	3,577	$	3,337

Maturities of Long-term Debt	'
	The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 2014 and thereafter, excluding unamortized premiums and discounts, are as follows (in millions):


	2014		$	22

	2015		261

	2016		222

	2017		14

	2018		839

	2019 and thereafter		2,229

	Total		$	3,587

Future Cash Payments for Capital and Financial Leases	'
	Future cash payments for capital and financial leases as of December 31, 2013, were as follows (in millions):


	2014		$	74

	2015		74

	2016		73

	2017		74

	2018		73

	2019 and thereafter		1,049

	Total minimum lease payments		1,417

	Less:
	Executory costs		(166		)
	Amounts representing interest		(745		)
	Present value of net minimum lease payments		$	506

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping

The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):

2013

2012

Carrying

Fair

Carrying

Fair

Value

Long-term debt

3,071

3,596

3,294

4,074

Other_Net_Tables

Other, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Other Nonoperating Income (Expense) [Abstract]	'
Schedule of Other Nonoperating Income (Expense)	'
	Other, net as shown on the Consolidated Statements of Operations for the years ended December 31 consists of the following (in millions):


		2013			2012			2011

	Interest and dividend income	$	5		$	4		$	3

	Donations	—			(2		)	(5		)

	Interest expense on regulatory items	(2		)	(7		)	1

	Other	2			2			(25		)

	Total other, net	$	5		$	(3	)	$	(26	)

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Components of Income Tax Expense (Benefit)	'
	Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):


		2013				2012				2011

	Current – Federal	$	(1	)		$	(12	)		$	(1	)
	Deferred – Federal	96				151				73

	Investment tax credits	(1		)		(1		)		(1		)
	Total income tax expense	$	94			$	138			$	71

Effective Income Tax Rate Reconciliation	'
	A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:


		2013			2012			2011

	Federal statutory income tax rate	35	%		35	%		35	%
	Non-deductible MEHC Merger related expenses	3			—			—

	Effects of ratemaking	1			1			1

	Other	—			(1	)		(1	)

	Effective income tax rate	39	%		35	%		35	%
Components of Net Deferred Income Tax Liability	'
	The net deferred income tax liability consists of the following as of December 31 (in millions):


		2013				2012
	Deferred income tax assets:
	Federal net operating loss and credit carryforwards	$	265			$	264

	Capital and financial leases	177				15

	Employee benefits	11				35

	Regulatory liabilities	4				5

	Other	85				51

	Total deferred income tax assets	542				370

	Valuation allowance	(2		)		(1		)
	Total deferred income tax assets, net	540				369


	Deferred income tax liabilities:
	Property-related items	(1,145		)		(1,071		)
	Regulatory assets	(314		)		(284		)
	Capital and financial leases	(189		)		(14		)
	Other	(38		)		(53		)
	Total deferred income tax liabilities	(1,686		)		(1,422		)
	Net deferred income tax liability	$	(1,146	)		$	(1,053	)

	Reflected as:
	Deferred income taxes - current	$	152			$	49

	Deferred income taxes - long-term	(1,298		)		(1,102		)
	Net deferred income tax liability	$	(1,146	)		$	(1,053	)
Summary of Operating Loss Carryforwards	'
	The following table provides the Company's federal net operating loss and tax credit carryforwards and expiration dates as of December 31, 2013 (in millions):


	Net operating loss carryforwards	$	726

	Deferred income taxes on federal net operating loss carryforwards	$	254

	Expiration dates	2029-2033

	Other tax credits	$	11

	Expiration dates	2014-2033
Net Unrecognized Tax Benefits Roll Forward	'
	A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):


		2013				2012

	Beginning balance	$	4			$	24

	Additions for tax positions of prior years	—				1

	Reductions for tax positions of prior years	(1		)		(21		)
	Ending balance	$	3			$	4

Retirement_Plan_and_Postretire1

Retirement Plan and Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Amounts Recognized in Balance Sheet	'
	Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31(in millions):


		2013			2012
	Qualified Pension Plan:
	Other assets	$	13		$	—

	Other long-term liabilities	—			(21		)


	Non-Qualified Pension Plans:
	Customer deposits and other	(4		)	—

	Other long-term liabilities	(8		)	(13		)

	Other Postretirement Plans -
	Other long-term liabilities	(7		)	(15		)

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Asset Retirement Obligations	'
	The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):


		2013		2012

	Evaporative ponds and dry ash landfills	$	84	$	46

	Asbestos	4		3

	Other	12		11

	Total asset retirement obligations	$	100	$	60

Schedule of Change in Asset Retirement Obligation	'
	The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):


		2013		2012

	Beginning balance	$	60	$	61

	Accretion	3		3

	Change in estimated costs	37		(4		)

	Ending balance	$	100	$	60

Commitments_and_Contingencies_1

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Contractual Obligation, Fiscal Year Maturity Schedule	'
	The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2013 are as follows (in millions):


												2019 and
		2014		2015		2016		2017		2018		Thereafter		Total

	Purchased power	$	397	$	400	$	401	$	401	$	347	$	3,461	$	5,407

	Purchased power - not commercially operable	64		72		91		105		106		2,432		2,870

	Coal and natural gas	395		169		48		44		46		47		749

	Transportation	70		81		69		66		51		583		920

	Long-term service agreements	15		15		15		13		10		28		96

	Operating leases	7		6		5		4		4		92		118

	Total commitments	$	948	$	743	$	629	$	633	$	564	$	6,643	$	10,160

Supplemental_Cash_Flow_Disclos1

Supplemental Cash Flow Disclosures (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]	'
Schedule of Cash Flow, Supplemental Disclosures	'
	The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):


		2013		2012		2011

	Supplemental disclosure of cash flow information -
	Interest paid, net of amounts capitalized	$	209	$	208	$	219


	Supplemental disclosure of non-cash investing and financing transactions:
	Accruals related to property, plant and equipment additions	$	25	$	150	$	176

	ON Line transmission use financial lease obligation	$	419	$	—	$	—

Unaudited_Quarterly_Operating_1

Unaudited Quarterly Operating Results (Tables)	12 Months Ended
	Dec. 31, 2013
Unaudited Quarterly Operating Results [Abstract]	'
Unaudited Quarterly Operating Results	'


		Three-Month Periods Ended
		31-Mar-13			30-Jun-13		30-Sep-13		31-Dec-13

	Operating revenue	$	372		$	537	$	786	$	397

	Operating income	58			141		305		(69		)

	Net income	5			59		164		(83		)



		Three-Month Periods Ended
		31-Mar-12			30-Jun-12		30-Sep-12		31-Dec-12

	Operating revenue	$	396		$	553	$	802	$	394

	Operating income	53			147		346		56

	Net income	(1		)	62		195		2

Organization_and_Operations_De

Organization and Operations (Details) (MEHC Merger [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
MEHC Merger [Member]	'
Other Ownership Interests [Line Items]	'
One-time bill credit	$15
Number of days for retail customers credit	'30 days
Return on common equity percentage	10.00%
Recovery of loss on revenues	50.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Allowance for Doubtful Accounts (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Allowance for doubtful accounts	$8	$8

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Inventory (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Material and supplies inventory	$54	$53
Energy related inventory	$19	$25

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Property, Plant and Equipment, Net (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
AFUDC rate	8.09%	8.09%

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Income Taxes (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Regulatory asset, deferred income taxes	$165	$169
Regulatory liability, deferred income taxes	$4	$5

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Revenue Recognition (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Unbilled revenue	$103	$86

MergerRelated_Activities_Detai

Merger-Related Activities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]	'	'	'
Merger-related expenses	$52	$0	$0
MEHC Merger [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
One-time bill credit	15	'	'
Merger-related expenses	52	'	'
Change in control costs [Member] \| MEHC Merger [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Merger-related expenses	15	'	'
Stock compensation plan costs [Member] \| MEHC Merger [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Merger-related expenses	18	'	'
Investment banker fees [Member] \| MEHC Merger [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Merger-related expenses	15	'	'
Legal fees and other expenses [Member] \| MEHC Merger [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Merger-related expenses	$4	'	'

Property_Plant_and_Equipment_N2

Property, Plant and Equipment, Net (Details) (USD $)	12 Months Ended			1 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jul. 31, 2012	Aug. 31, 2011	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
				Telecommunication Towers [Member]	Telecommunication Towers [Member]	Telecommunication Towers [Member]	Regulated Operation [Member]	Regulated Operation [Member]	Unregulated Operation [Member]	Unregulated Operation [Member]
					Telecommunication_Towers
Utility plant in-service:	'	'	'	'	'	'	'	'	'	'
Generation	'	'	'	'	'	'	$3,789	$3,706	'	'
Distribution	'	'	'	'	'	'	2,936	2,885	'	'
Transmission	'	'	'	'	'	'	1,743	1,189	'	'
General intangible plant	'	'	'	'	'	'	645	583	'	'
Utility plant in-service	'	'	'	'	'	'	9,113	8,363	'	'
Accumulated depreciation and amortization	'	'	'	'	'	'	2,217	2,035	'	'
Utility plant in-service, net	6,899	6,344	'	'	'	'	6,896	6,328	3	16
Construction work-in-progress	93	568	'	'	'	'	'	'	'	'
Property, plant and equipment, net	6,992	6,912	'	'	'	'	'	'	'	'
Average depreciation and amortization rate	3.26%	3.22%	3.04%	'	'	'	'	'	'	'
Asset impairment charge	31	'	'	'	'	'	'	'	'	'
Number of telecommunication towers sold	'	'	'	'	37	'	'	'	'	'
Proceeds from sale of telecommunication towers	'	'	'	32	32	'	'	'	'	'
Proceeds from sale of assets, restricted to ratepayer rebates	'	'	'	27	'	'	'	'	'	'
Gain on disposition of assets	'	'	'	'	'	$6	'	'	'	'

Jointly_Owned_Utility_Faciliti2

Jointly Owned Utility Facilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Jointly Owned Utility Plant Interests [Line Items]	'
Facility in Service	$648
Accumulated Depreciation and Amortization	216
Construction Work-in-Progress	6
ON Line Transmission Line [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Company Share	24.00%	[1]
Facility in Service	140	[1]
Accumulated Depreciation and Amortization	0	[1]
Construction Work-in-Progress	0	[1]
Other Transmission Facilities [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Company Share	'Various
Facility in Service	68
Accumulated Depreciation and Amortization	27
Construction Work-in-Progress	0
Navajo Generating Station [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Company Share	11.00%
Facility in Service	198
Accumulated Depreciation and Amortization	132
Construction Work-in-Progress	3
Silverhawk Generating Station [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Company Share	75.00%
Facility in Service	242
Accumulated Depreciation and Amortization	57
Construction Work-in-Progress	$3
ON Line Transmission Line [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
GBT-South's share in the ON Line project (in hundredths)	75.00%

[1]	ON Line was placed in-service December 2013. The Company and Sierra Pacific entered into a long-term transmission use agreement with Great Basin Transmission South, LLC's 75% interest in ON Line. Refer to NoteB 9 for additional information.

Regulatory_Matters_Regulatory_

Regulatory Matters - Regulatory Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets [Line Items]	'		'
Regulatory assets	$81		$0
Regulatory assets, noncurrent	1,057		1,028
Total regulatory assets	1,138		1,028
Regulatory assets not earning a return on investment	598		459
Deferred income taxes [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P28Y	[1]	'
Total regulatory assets	165	[1]	169	[1]
Deferred excess energy costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P2Y		'
Total regulatory assets	159		87
Merger costs from 1999 merger [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P29Y		'
Total regulatory assets	155		162
Abandoned projects [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P7Y		'
Total regulatory assets	115		42
Asset retirement obligations [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P4Y		'
Total regulatory assets	98		58
Employee benefit plans [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P13Y	[2]	'
Total regulatory assets	83	[2]	137	[2]
Demand side resources [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P3Y		'
Total regulatory assets	70		123
Legacy meters [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P7Y		'
Total regulatory assets	65		61
Deferred operating costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P29Y		'
Total regulatory assets	63		65
Unrealized loss on regulated derivative contracts [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'P5Y		'
Total regulatory assets	47		0
Other [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory asset amortization period years	'Various		'
Total regulatory assets	$118		$124

[1]	Amounts primarily represent income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.
[2]	Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

Regulatory_Matters_Regulatory_1

Regulatory Matters - Regulatory Liabilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Liabilities [Line Items]	'		'
Current liabilities	$74		$86
Noncurrent liabilities	312		323
Total regulatory liabilities	386		409
Cost of removal [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'P37Y	[1]	'
Total regulatory liabilities	273	[1]	252	[1]
Energy efficiency program [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'P1Y		'
Total regulatory liabilities	57		37
Renewable energy program [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'P1Y		'
Total regulatory liabilities	18		0
Deferred income taxes [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'P19Y		'
Total regulatory liabilities	4		5
Deferred energy over collected [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'P1Y		'
Total regulatory liabilities	0		86
Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory liability amortization period years	'Various		'
Total regulatory liabilities	$34		$29

[1]	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

Regulatory_Matters_General_Dis

Regulatory Matters - General Disclosures (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2013	31-May-13	Feb. 21, 2014	Dec. 31, 2013
In Millions, unless otherwise specified			PUCN [Member]	PUCN [Member]	Federal Energy Regulatory Commission [Member]	Federal Energy Regulatory Commission [Member]	MEHC Merger [Member]
						Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]	'	'	'	'	'	'	'
Energy efficiency implementation rates, disallowed revenue	'	'	$11	'	'	'	'
Recovery of loss on revenues	'	'	'	'	'	'	50.00%
Regulatory liabilities	386	409	'	12	'	'	'
Public utilities, approved rate increase (decrease), amount	'	'	'	'	'	5	'
Requested rate increase (decrease), amended, amount	'	'	'	'	$17	'	'

Risk_Management_Details

Risk Management (Details) (Commodity Contract [Member])	12 Months Ended
	Dec. 31, 2013
	MMBTU
Natural Gas [Member]	'
Derivatives, Fair Value [Line Items]	'
Net notional amount of outstanding derivative contracts	118,000,000
Energy Sales [Member]	'
Derivatives, Fair Value [Line Items]	'
Net notional amount of outstanding derivative contracts	4,000,000

Credit_Facility_Details

Credit Facility (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Letter of Credit [Member]
			Federal Funds Rate [Member]	London Interbank Offered Rate (LIBOR) [Member]	London Interbank Offered Rate (LIBOR) [Member]	Base Rate [Member]
			Minimum [Member]		Minimum [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'
Maximum borrowing capacity	$500,000,000	'	'	'	'	'	'
Drawings outstanding	$0	$0	'	'	'	'	$3,000,000
Basis spread on variable rate	'	'	0.50%	1.13%	1.00%	0.13%	'

LongTerm_Debt_Summary_Details

Long-Term Debt - Summary (Details) (USD $)	Dec. 31, 2013	Nov. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Nov. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'	'
Par value	$3,587	'	'
Current liabilities	22	'	106
Noncurrent liabilities	3,555	'	3,231
Total long-term debt	3,577	'	3,337
Mortgage securities, 7.375%, Series U due 2014 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	0	'	'
Total long-term debt	0	'	125
Stated interest rate	7.38%	7.38%	7.38%
Mortgage Securities, 5.875%, Series L due 2015 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	250	'	'
Total long-term debt	250	'	250
Stated interest rate	5.88%	'	5.88%
Mortgage Securities, 5.950%, Series M due 2016 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	210	'	'
Total long-term debt	210	'	210
Stated interest rate	5.95%	'	5.95%
Mortgage Securities, 6.500%, Series O due 2018 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	325	'	'
Total long-term debt	324	'	324
Stated interest rate	6.50%	'	6.50%
Mortgage Securities, 6.500%, Series S due 2018 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	500	'	'
Total long-term debt	499	'	499
Stated interest rate	6.50%	'	6.50%
Mortgage Securities, 7.125%, Series V due 2019 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	500	'	'
Total long-term debt	501	'	501
Stated interest rate	7.13%	'	7.13%
Mortgage Securities, 6.650%, Series N due 2036 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	370	'	'
Total long-term debt	363	'	363
Stated interest rate	6.65%	'	6.65%
Mortgage Securities, 6.750%, Series R due 2037 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	350	'	'
Total long-term debt	349	'	349
Stated interest rate	6.75%	'	6.75%
Mortgage Securities, 5.375%, Series X due 2040 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	250	'	'
Total long-term debt	249	'	249
Stated interest rate	5.38%	'	5.38%
Mortgage Securities, 5.450%, Series Y due 2041 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	250	'	'
Total long-term debt	250	'	250
Stated interest rate	5.45%	'	5.45%
Industrial Development Refunding Revenue Bonds, Series 2000A, due 2020 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	0	'	'
Total long-term debt	0	'	98
Pollution Control Revenue Bonds, Series 2006A due 2032 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	38	'	'
Total long-term debt	38	'	38
Pollution Control Revenue Bonds, Series 2006 due 2036 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	38	'	'
Total long-term debt	38	'	38
Capital lease obligations, 3.01% to 11.60%, due through 2054 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Par value	506	'	'
Total long-term debt	$506	'	$43
Minimum [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	0.45%	'	'
Minimum [Member] \| Pollution Control Revenue Bonds, Series 2006 due 2036 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	'	'	0.58%
Minimum [Member] \| Capital lease obligations, 3.01% to 11.60%, due through 2054 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	3.01%	'	3.01%
Maximum [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	0.46%	'	'
Maximum [Member] \| Pollution Control Revenue Bonds, Series 2006 due 2036 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	'	'	0.63%
Maximum [Member] \| Capital lease obligations, 3.01% to 11.60%, due through 2054 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Variable interest rate	11.60%	'	11.60%

LongTerm_Debt_Narrative_Detail

Long-Term Debt - Narrative (Details) (USD $)	12 Months Ended	1 Months Ended			1 Months Ended			1 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Aug. 31, 2013	Jul. 31, 2013	Dec. 31, 2013	Nov. 30, 2013	Dec. 31, 2012	Apr. 30, 2012
	Dec. 31, 2013	Subsequent Event [Member]	Industrial Development Refunding Revenue Bonds, Series 2000A, due 2020 [Member]	Industrial Development Refunding Revenue Bonds, Series 2000A, due 2020 [Member]	Mortgage securities, 7.375%, Series U due 2014 [Member]	Mortgage securities, 7.375%, Series U due 2014 [Member]	Mortgage securities, 7.375%, Series U due 2014 [Member]	General and Refunding Mortgage Securities, NPC Series I [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'
Debt required to be tendered	$3,000,000,000	'	'	'	'	'	'	'
Redemption price percentage of par	101.00%	'	100.00%	'	100.70%	'	'	'
Amount of debt tendered	'	5,000,000	98,000,000	'	125,000,000	'	'	130,000,000
Notice of redemption	'	'	'	100,000,000	'	125,000,000	'	'
Stated interest rate	'	'	'	'	7.38%	7.38%	7.38%	6.50%
Draw on credit facility	'	'	'	'	'	'	'	120,000,000
Cash used to pay down debt	'	'	'	'	'	'	'	10,000,000
Eligible property subject to lien	$3,700,000,000	'	'	'	'	'	'	'

LongTerm_Debt_Maturity_Schedul

Long-Term Debt - Maturity Schedule (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Debt Disclosure [Abstract]	'
2014	$22
2015	261
2016	222
2017	14
2018	839
2019 and thereafter	2,229
Total long-term debt	$3,587

LongTerm_Debt_Capital_Leases_N

Long-Term Debt - Capital Leases - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
	option
Building [Member]	'
Capital Leased Assets [Line Items]	'
Terms of lease	'30 years
Number of renewal options under lease	5
Number of years In renewal period	'5 years
Number of renewal options exercised	3
Number remaining renewal options under lease	2
Maximum additional term of lease with remaining extensions	'10 years
Capital assets	$39
Land and Building [Member]	'
Capital Leased Assets [Line Items]	'
Terms of lease	'20 years
Number of renewal options under lease	3
Number of years In renewal period	'10 years
Capital assets	10
Long-Term Energy Purchase Contracts [Member]	'
Capital Leased Assets [Line Items]	'
Number of years In renewal period	'30 years
Capital assets	$71
Equipment [Member]	'
Capital Leased Assets [Line Items]	'
Terms of lease	'7 years
ON Line Transmission Line [Member]	'
Capital Leased Assets [Line Items]	'
Terms of lease	'41 years
GBT-South's share in the ON Line project (in hundredths)	75.00%
Utilities' aggregate share in transmission line project (in hundredths)	25.00%
Nevada Power Company [Member] \| ON Line Transmission Line [Member]	'
Capital Leased Assets [Line Items]	'
Utilities' aggregate share in transmission line project (in hundredths)	95.00%
Sierra Pacific Power Company [Member] \| ON Line Transmission Line [Member]	'
Capital Leased Assets [Line Items]	'
Utilities' aggregate share in transmission line project (in hundredths)	5.00%

LongTerm_Debt_Capital_Leases_M

Long-Term Debt - Capital Leases - Maturity Schedule (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Debt Disclosure [Abstract]	'
2014	$74
2015	74
2016	73
2017	74
2018	73
2019 and thereafter	1,049
Total minimum lease payments	1,417
Executory costs	-166
Amounts representing interest	-745
Present value of net minimum lease payments	$506

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Not Designated as Hedging Instrument [Member], Commodity Contract [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Net Regulatory Asset (Liability), Unrealized Loss (Gain) On Derivative Contracts	$47
Recurring [Member] \| Customer deposits and other [Member] \| Level 3 [Member]	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Derivative assets (liabilities)	-9
Recurring [Member] \| Other long-term liabilities [Member] \| Level 3 [Member]	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Derivative assets (liabilities)	($38)

Fair_Value_Measurements_Debt_D

Fair Value Measurements - Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt	$3,071	$3,294
Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt, fair value	$3,596	$4,074

Other_Net_Details

Other, Net (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Component of Other Income (Expense), Nonoperating [Line Items]	'	'	'
Other, net	$5	($3)	($26)
Interest and dividend income [Member]	'	'	'
Component of Other Income (Expense), Nonoperating [Line Items]	'	'	'
Other, net	5	4	3
Donations [Member]	'	'	'
Component of Other Income (Expense), Nonoperating [Line Items]	'	'	'
Other, net	0	-2	-5
Interest Expense on Regulatory Items [Member]	'	'	'
Component of Other Income (Expense), Nonoperating [Line Items]	'	'	'
Other, net	-2	-7	1
Other, net [Member]	'	'	'
Component of Other Income (Expense), Nonoperating [Line Items]	'	'	'
Other, net	$2	$2	($25)

Income_Taxes_Components_of_Inc

Income Taxes Components of Income Tax Expense (Benefit) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Current - Federal	($1)	($12)	($1)
Deferred - Federal	96	151	73
Investment tax credits	-1	-1	-1
Total income tax expense	$94	$138	$71

Income_Taxes_Reconciliation_of

Income Taxes Reconciliation of Effective Income Tax Rate (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]	'	'	'
Federal statutory income tax rate	35.00%	35.00%	35.00%
Non-deductible MEHC Merger related expenses	3.00%	0.00%	0.00%
Effects of ratemaking	1.00%	1.00%	1.00%
Other	0.00%	-1.00%	-1.00%
Effective income tax rate	39.00%	35.00%	35.00%

Income_Taxes_Components_of_Net

Income Taxes Components of Net Deferred Income Tax Liability (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred income tax assets:	'	'
Federal net operating loss and credit carryforwards	$265	$264
Capital and financial leases	177	15
Employee benefits	11	35
Regulatory liabilities	4	5
Other	85	51
Total deferred income tax assets	542	370
Valuation allowance	-2	-1
Total deferred income tax assets, net	540	369
Deferred income tax liabilities:	'	'
Property-related items	-1,145	-1,071
Regulatory assets	-314	-284
Capital and financial leases	-189	-14
Other	-38	-53
Total deferred income tax liabilities	-1,686	-1,422
Net deferred income tax liability	-1,146	-1,053
Reflected as:	'	'
Deferred income taxes - current	152	49
Deferred income taxes - long-term	($1,298)	($1,102)

Income_Taxes_Summary_of_Operat

Income Taxes Summary of Operating Loss Carryforwards (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Net operating loss carryforwards	$726
Deferred income taxes on federal net operating loss carryforwards	254
Other tax credits	$11

Income_Taxes_Net_Unrecognized_

Income Taxes Net Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'
Beginning balance	$4	$24
Additions for tax positions of prior years	0	1
Reductions for tax positions of prior years	-1	-21
Ending balance	3	4
Unrecognized tax benefits that would impact effective tax rate	$2	$2

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Kern River [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Related Party Transaction, Purchases from Related Party	$68	$66	$50
Due to Affiliate, Current	5	'	'
MEHC [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Due from Affiliate, Current	2	'	'
PacifiCorp [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Related Party Transaction, Purchases from Related Party	2	62	54
Due to Affiliate, Current	0	7	'
Due from Affiliate, Current	0	1	'
Revenue from Related Parties	3	7	3
Sierra Pacific Power Company [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Due from Affiliate, Current	6	3	'
Related Party Transaction, Expense Reimbursement	22	22	22
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	24	20	18
Sierra Pacific Power Company [Member] \| Electric Distribution [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Related Party Transaction, Purchases from Related Party	1	1	2
Due from Affiliate, Current	3	4	'
Revenue from Related Parties	36	20	22
NV Energy, Inc. [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Due to Affiliate, Current	60	39	'
Related Party Transaction, Expense Reimbursement	45	27	23
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	$0	$1	$1

Retirement_Plan_and_Postretire2

Retirement Plan and Postretirement Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Qualified Pension Plan [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension and other postretirement benefit contributions	$0	$0	$15
Non-Qualified Pension Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension and other postretirement benefit contributions	0	0	0
Other Postretirement Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension and other postretirement benefit contributions	0	0	0
NV Energy, Inc. [Member] \| Qualified Pension Plan [Member] \| Other assets [Member]	'	'	'
Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Other assets	13	0	'
NV Energy, Inc. [Member] \| Qualified Pension Plan [Member] \| Other long-term liabilities [Member]	'	'	'
Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Other long-term liabilities	0	-21	'
NV Energy, Inc. [Member] \| Non-Qualified Pension Plans [Member] \| Other long-term liabilities [Member]	'	'	'
Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Other long-term liabilities	-8	-13	'
NV Energy, Inc. [Member] \| Non-Qualified Pension Plans [Member] \| Customer deposits and other [Member]	'	'	'
Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Customer deposits and other	-4	0	'
NV Energy, Inc. [Member] \| Other Postretirement Plans [Member] \| Other long-term liabilities [Member]	'	'	'
Amounts Recognized in Balance Sheet [Abstract]	'	'	'
Other long-term liabilities	($7)	($15)	'

Asset_Retirement_Obligation_By

Asset Retirement Obligation By Type (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligations By Type [Line Items]	'		'		'
Cost of removal regulatory liability	$386		$409		'
Total asset retirement obligations	100		60		61
Evaporative Ponds and Dry Ash Landfills [Member]	'		'		'
Asset Retirement Obligations By Type [Line Items]	'		'		'
Total asset retirement obligations	84		46		'
Asbestos [Member]	'		'		'
Asset Retirement Obligations By Type [Line Items]	'		'		'
Total asset retirement obligations	4		3		'
Other [Member]	'		'		'
Asset Retirement Obligations By Type [Line Items]	'		'		'
Total asset retirement obligations	12		11		'
Cost of removal [Member]	'		'		'
Asset Retirement Obligations By Type [Line Items]	'		'		'
Cost of removal regulatory liability	$273	[1]	$252	[1]	'

[1]	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

Asset_Retirement_Obligations_C

Asset Retirement Obligations Change in Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Beginning balance	$60	$61
Accretion	3	3
Change in estimated costs	37	-4
Ending balance	$100	$60

Commitments_and_Contingencies_2

Commitments and Contingencies - Commitments Table (Details) (USD $)	Dec. 31, 2013	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013	Subsequent Event [Member]	Purchased power [Member]	Purchased power, not commercially operable [Member]	Coal and natural gas [Member]	Transportation [Member]	Long-term service agreements [Member]
Contractual Obligation [Line Items]	'	'	'	'	'	'	'
Purchase Obligation, Due in Next Twelve Months	'	$7	$397	$64	$395	$70	$15
Purchase Obligation, Due in Second Year	'	8	400	72	169	81	15
Purchase Obligation, Due in Third Year	'	7	401	91	48	69	15
Purchase Obligation, Due in Fourth Year	'	7	401	105	44	66	13
Purchase Obligation, Due in Fifth Year	'	5	347	106	46	51	10
Purchase Obligation, Due Thereafter	'	38	3,461	2,432	47	583	28
Purchase Obligation	'	'	5,407	2,870	749	920	96
Operating Leases, Future Minimum Payments Due, Next Twelve Months	7	'	'	'	'	'	'
Operating Leases, Future Minimum Payments, Due in Two Years	6	'	'	'	'	'	'
Operating Leases, Future Minimum Payments, Due in Three Years	5	'	'	'	'	'	'
Operating Leases, Future Minimum Payments, Due in Four Years	4	'	'	'	'	'	'
Operating Leases, Future Minimum Payments, Due in Five Years	4	'	'	'	'	'	'
Operating Leases, Future Minimum Payments, Due Thereafter	92	'	'	'	'	'	'
Operating Leases, Future Minimum Payments Due	118	'	'	'	'	'	'
Total commitments, Due in Next Twelve Months	948	'	'	'	'	'	'
Total commitments, Due in Second Year	743	'	'	'	'	'	'
Total commitments, Due in Third Year	629	'	'	'	'	'	'
Total commitments, Due in Fourth Year	633	'	'	'	'	'	'
Total commitments, Due in Fifth Year	564	'	'	'	'	'	'
Total commitments, Due after Fifth Year	6,643	'	'	'	'	'	'
Total commitments	$10,160	'	'	'	'	'	'

Commitments_and_Contingencies_3

Commitments and Contingencies - Narrative (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]	'	'	'	'
Rent expense for power purchase agreements meeting definition of operating lease	'	$400	$353	$296
Operating leases rent expense	'	9	10	11
Amount awarded unpaid rent	1	'	'	'
Amount awarded inverse condemnation and interest	5	'	'	'
Total judgment amount	'	$12	'	'

Supplemental_Cash_Flow_Disclos2

Supplemental Cash Flow Disclosures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	$209	$208	$219
Supplemental disclosure of non-cash investing and financing transactions:	'	'	'
Accruals related to property, plant and equipment additions	25	150	176
ON Line transmission use financial lease obligation	$419	$0	$0

Unaudited_Quarterly_Operating_2

Unaudited Quarterly Operating Results (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unaudited Quarterly Operating Results [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Operating revenue	$397	$786	$537	$372	$394	$802	$553	$396	$2,092	$2,145	$2,054
Operating income	-69	305	141	58	56	346	147	53	435	602	444
Net income	($83)	$164	$59	$5	$2	$195	$62	($1)	$145	$258	$133

Schedule_II_Consolidated_Valua1

Schedule II Consolidated Valuation and Qualifying Accounts (Details) (Reserve for uncollectible accounts receivable [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reserve for uncollectible accounts receivable [Member]	'	'	'
Valuation and Qualifying Accounts Disclosure [Line Items]	'	'	'
Balance at Beginning of Year	$8	$7	$26
Charged to Income	15	15	14
Deductions	-15	-14	-33
Balance at End of Year	$8	$8	$7