Williams Partners Inactive 8-K19 May 14Other EventsFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2013
Document and Entity Information [Abstract]	'
Entity Registrant Name	'Williams Partners L.P.
Entity Central Index Key	'0001324518
Document Type	'8-K
Document Period End Date	31-Dec-13
Amendment Flag	'false

Consolidated_Statement_of_Comp

Consolidated Statement of Comprehensive Income (USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Service revenues	$2,914	$2,714	$2,518
Product sales	3,921	4,757	5,398
Total revenues	6,835	7,471	7,916
Costs and expenses:	'	'	'
Product costs	3,027	3,501	3,934
Operating and maintenance expenses	1,080	1,019	982
Depreciation and amortization expenses	791	734	637
Selling, general, and administrative expenses	519	583	431
Other (income) expense - net	11	24	18
Total costs and expenses	5,428	5,861	6,002
Operating income	1,407	1,610	1,914
Equity earnings (losses)	104	111	142
Interest incurred	-477	-458	-439
Interest capitalized	90	54	24
Other income (expense) - net	25	16	9
Income before income taxes	1,149	1,333	1,650
Provision (benefit) for income taxes	30	42	46
Net income	1,119	1,291	1,604
Less: Net income attributable to noncontrolling interests	3	0	0
Net Income attributable to controlling interests	1,116	1,291	1,604
Allocation of net income for calculation of earnings per common unit:	'	'	'
Net income attributable to controlling interests	1,116	1,291	1,604
Allocation of net income to general partner	505	646	534
Allocation of net income to common units	611	645	1,070
Basic net income per common unit	$1.45	$1.89	$3.69
Diluted net income per common unit	$1.45	$1.89	$3.69
Basic weighted average number of common units outstanding (thousands)	420,916	341,981	290,255
Diluted weighted average number of common units outstanding (thousands)	420,916	341,981	290,255
Cash distributions per common unit	$3.48	$3.21	$2.96
Other Comprehensive Income (Loss):	'	'	'
Net unrealized gain (loss) from derivative instruments	1	30	-17
Reclassifications into earnings of net derivative instruments (gain) loss	0	-30	18
Foreign currency translation adjustments	-56	20	-16
Other comprehensive income (loss)	-55	20	-15
Comprehensive income	1,064	1,311	1,589
Less: Comprehensive income attributable to noncontrolling interests	3	0	0
Comprehensive income attributable to controlling interests	$1,061	$1,311	$1,589

Consolidated_Balance_Sheet

Consolidated Balance Sheet (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$110	$82
Trade accounts and notes receivable, net	568	589
Inventories	194	175
Other current assets	96	96
Total current assets	968	942
Investments	2,187	1,800
Property, plant, and equipment - net	17,625	15,156
Goodwill	646	649
Other intangible assets	1,642	1,702
Regulatory assets, deferred charges, and other	503	429
Total assets	23,571	20,678
Accounts payable:	'	'
Trade	889	937
Affiliate	104	105
Accrued interest	115	110
Asset retirement obligations	64	68
Other accrued liabilities	375	207
Commercial paper	225	0
Total current liabilities	1,772	1,427
Long-term debt	9,057	8,437
Asset retirement obligations	497	511
Regulatory liabilities, deferred income, and other	678	612
Contingent liabilities and commitments (Note 15)	'	'
Partners' equity	'	'
Common units (438,625,699 units outstanding at December 31, 2013 and 397,963,199 units outstanding at December 31, 2012)	11,596	10,372
General partner	-536	-842
Accumulated other comprehensive income (loss)	92	147
Total partners' equity	11,152	9,677
Noncontrolling interests in consolidated subsidiaries	415	14
Total equity	11,567	9,691
Total liabilities and equity	$23,571	$20,678

Consolidated_Balance_Sheet_Par

Consolidated Balance Sheet (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Equity:	'	'
Limited partners capital account units outstanding	438,625,699	397,963,199

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Equity (USD $)	Total	Common Units	General Partner	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
In Millions	Total	Common Units	General Partner	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Beginning Balance at Dec. 31, 2010	$5,826	$6,564	($880)	$142	$0
Net income	1,604	1,088	516	0	0
Other comprehensive income (loss)	-15	0	0	-15	0
Cash distributions (Note 4)	-1,124	-842	-282	0	0
Distributions to The Williams Companies, Inc - net	-65	0	-65	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	-123	0	-123	0	0
Contributions from general partner	31	0	31	0	0
Other	-12	0	-12	0	0
Ending Balance at Dec. 31, 2011	6,122	6,810	-815	127	0
Net income	1,291	672	619	0	0
Other comprehensive income (loss)	20	0	0	20	0
Cash distributions (Note 4)	-1,440	-1,056	-384	0	0
Distributions to The Williams Companies, Inc - net	-16	0	-16	0	0
Sales of common units (Note 13)	2,559	2,559	0	0	0
Issuances of common units related to acquisitions (Note 13)	1,044	1,044	0	0	0
Issuances Of Common Units In Common Control Transactions (Note 13)	7	345	-338	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	0	'	'	'	'
Contributions from general partner	93	0	93	0	0
Contributions from noncontrolling interests	14	0	0	0	14
Other	-3	-2	-1	0	0
Ending Balance at Dec. 31, 2012	9,691	10,372	-842	147	14
Net income	1,119	660	456	0	3
Other comprehensive income (loss)	-55	0	0	-55	0
Cash distributions (Note 4)	-1,846	-1,422	-424	0	0
Contributions from The Williams Companies, inc net	221	0	221	0	0
Sales of common units (Note 13)	1,962	1,962	0	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	0	'	'	'	'
Contributions from general partner	78	0	78	0	0
Contributions from noncontrolling interests	398	0	0	0	398
Other	-1	24	-25	0	0
Ending Balance at Dec. 31, 2013	$11,567	$11,596	($536)	$92	$415

Consolidated_Statement_of_Cash

Consolidated Statement of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES:	'	'	'
Net income	$1,119	$1,291	$1,604
Adjustments to reconcile to net cash provided by operations:	'	'	'
Depreciation and amortization	791	734	637
Cash provided (used) by changes in current assets and liabilities:	'	'	'
Accounts and notes receivable	21	32	-113
Inventories	-17	10	56
Other current assets and deferred charges	25	25	-4
Accounts payable	-32	-81	135
Accrued liabilities	171	-23	112
Affiliate accounts receivable and payable - net	-1	42	-100
Other, including changes in noncurrent assets and liabilities	92	103	103
Net cash provided by operating activities	2,169	2,133	2,430
FINANCING ACTIVITIES:	'	'	'
Proceeds from (payments of) commercial paper - net	224	0	0
Proceeds from long-term debt	2,699	2,639	1,596
Payments of long-term debt	-2,080	-1,440	-1,184
Proceeds from sales of common units	1,962	2,559	0
General partner contributions	53	93	31
Distributions to limited partners and general partner	-1,846	-1,440	-1,124
Contributions from noncontrolling interests	398	13	0
Excess of purchase price over contributed basis of business and investment	0	0	-123
Contributions from (distributions to) The Williams Companies, Inc. - net	221	9	-65
Other - net	-36	5	-15
Net cash provided (used) by financing activities	1,595	2,438	-884
Property, plant and equipment:	'	'	'
Capital expenditures	-3,316	-2,366	-1,177
Net proceeds from dispositions	3	22	5
Purchases of businesses	0	-2,049	-41
Purchase of businesses and investments from affiliates	25	-25	-174
Purchases of and contributions to equity method investments	-439	-471	-197
Purchase of ARO trust investments	-58	-34	-41
Proceeds from sale of ARO trust investments	46	43	56
Other - net	3	53	1
Net cash used by investing activities	-3,736	-4,827	-1,568
Increase (decrease) in cash and cash equivalents	28	-256	-22
Cash and cash equivalents at beginning of year	82	338	360
Cash and cash equivalents at end of year	$110	$82	$338

General_and_Basis_of_Presentat

General and Basis of Presentation	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization, Basis of Presentation, and Description of Business	'
	Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
	General
	We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2013, Williams owns an approximate 62 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us). Our operations are located in the United States and Canada.
	Description of Business
	Our operations are located in North America and are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
	Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 47.5 percent equity investment in Caiman Energy II, LLC (Caiman II).
	Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), and a 60 percent equity investment in Discovery Producer Services LLC (Discovery).
	West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).
	NGL & Petchem Services is comprised of our 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest of an NGL fractionator near Conway, Kansas, and a 50 percent equity investment in Overland Pass Pipeline, LLC (OPPL).
	Basis of Presentation

	In February 2014, we acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of $25 million of cash (subject to certain closing adjustments), 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All outstanding Class D units will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Acquisition provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. These Canadian operations are reported in our NGL & Petchem Services segment.

	Prior period amounts and disclosures have been recast for this transaction. The effect of recasting our financial statements to account for this transaction increased net income by $49 million, $59 million and $93 million for the years ended 2013, 2012, and 2011, respectively, and also resulted in Foreign currency translation adjustments of $(56) million , $20 million , and $(16) million for the years ended 2013, 2012, and 2011, respectively, reflected within Other comprehensive income (loss). This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
	In November 2012, we acquired an entity that holds an 83.3 percent undivided interest in an olefins-production facility in Geismar, Louisiana, and associated assets from Williams for total consideration of 42,778,812 of our limited partner units, $25 million in cash, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest (Geismar Acquisition). The acquired entity was an affiliate of Williams at the time of the acquisition; therefore, the acquisition was accounted for as a common control transaction, whereby the acquired assets and liabilities were combined with ours at their historical amounts. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. In first-quarter 2013, we received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to our May 2013 distribution related to a working capital adjustment associated with the acquisition.
	In May 2011, we acquired a 24.5 percent equity interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In June 2012, we acquired an additional 1 percent interest in Gulfstream from a subsidiary of Williams in exchange for 238,050 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. The equity interests acquired in these transactions were affiliates of Williams at the time of the acquisitions; therefore, each was accounted for as a common control transaction. The equity interests acquired were combined with our investments as of the date of transfer such that our historical results of operations for periods prior to the acquisitions were unchanged. These transactions are collectively referred to as the Gulfstream Acquisitions and the investment is reported in our Atlantic-Gulf segment.
	Summary of Significant Accounting Policies
	Principles of consolidation
	The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:


	•	Determining whether an entity is a variable interest entity (VIE);


	•	Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;


	•	Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;


	•	Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

	We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.
	Common control transactions
	Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
	Significant estimates and assumptions include:

	•	Impairment assessments of investments, property, plant, and equipment, goodwill and other identifiable intangible assets;

	•	Litigation-related contingencies;

	•	Environmental remediation obligations;

	•	Asset retirement obligations;

	•	Acquisition related purchase price allocations.

	These estimates are discussed further throughout these notes.
	Regulatory accounting
	Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for non regulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:


		December 31,

		2013			2012

		(Millions)

	Current assets reported within Other current assets	$	39		$	39

	Noncurrent assets reported within Regulatory assets, deferred charges, and other	315			275

Total regulated assets	$	354		$	314



Current liabilities reported within Other accrued liabilities	$	19		$	15

Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289			250

Total regulated liabilities	$	308		$	265




Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventory valuation
All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment
Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (See Note 11 – Property, Plant and Equipment.)
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income.
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Goodwill
Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.
Other intangible assets
Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facility and commercial paper program
Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt, Banking Arrangements, and Leases.)
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:


Derivative Treatment		Accounting Method
Normal purchases and normal sales exception		Accrual accounting
Designated in a qualifying hedging relationship		Hedge accounting
All other derivatives		Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.
Service revenues
Revenues include services pursuant to long-term firm transportation and storage agreements within our interstate natural gas pipeline businesses. These agreements provide for a reservation charge based on the volume of a contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services, and storage injection and withdrawal services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.
We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.
Our Canadian business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating income in the Consolidated Statement of Comprehensive Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Income taxes
We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations. Other income taxes on net income are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.
Foreign deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings per unit
We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

Pension and other postretirement benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 9 – Benefit Plans.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
Foreign currency translation
Our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI.
Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Comprehensive Income.
Accumulated Other Comprehensive Income (Loss)
AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income in any of the periods presented.

Acquisitions_Goodwill_and_Othe

Acquisitions Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions Goodwill and Other Intangible Assets [Text Block]	'
	Note 2 – Acquisitions, Goodwill, and Other Intangible Assets
	Business Combinations
	In addition to the entities and assets acquired in the common control transactions described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, we note the following additional acquisitions.
	On February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of a natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as gathering lines in southern New York.
	On April 27, 2012, we completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC in exchange for $1.72 billion in cash and 11,779,296 of our common units valued at $603 million (Caiman Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania, and eastern Ohio. Acquisition transaction costs of $16 million were incurred during 2012 by Northeast G&P related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income.
	The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Northeast G&P segment:


		Laser			Caiman
		(Millions)
	Assets held-for-sale	$	18		$	—

	Other current assets	3			16

	Property, plant, and equipment	158			656

	Intangible assets:
	Customer contracts	316			1,141

	Customer relationships	—			250

	Other	2			2

	Current liabilities	(21		)	(94		)
	Noncurrent liabilities	—			(3		)

	Identifiable net assets acquired	476			1,968

	Goodwill	290			356

		$	766		$	2,324

	Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Comprehensive Income in 2012 are not material. Supplemental pro forma revenue and earnings for the pre-acquisition periods reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Comprehensive Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.
	Goodwill and Other Intangible Assets
	Goodwill
	The Laser and Caiman Acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to our Northeast G&P segment (the reporting unit). Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Our annual goodwill impairment review did not result in a goodwill impairment in 2013.
	Other Intangible Assets
	Other intangible assets primarily relate to gas gathering, processing and fractionation contracts and relationships with customers recognized in the Laser and Caiman Acquisitions. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired customer contracts and relationships, which were offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. The intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.
	The gross carrying amount and accumulated amortization of Other intangible assets at December 31 are as follows:


		2013						2012
		Gross Carrying Amount			Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
		(Millions)
	Customer contracts	$	1,493		$	(88	)	$	1,493	$	(38	)

	Customer relationships	250			(14		)	250		(6		)

	Other	4			(3		)	4		(1		)

	Total	$	1,747		$	(105	)	$	1,747	$	(45	)

	We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the customer contracts associated with the Laser and Caiman Acquisitions were approximately 9 years and 18 years, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investments required.
	The aggregate amortization expense related to Other intangible assets was $60 million, $43 million and $2 million in 2013, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $60 million.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2013
Variable Interest Entity Disclosures [Abstract]	'
Variable Interest Entity Disclosures [Textblock]	'
	Note 3 – Variable Interest Entities

	Consolidated VIEs
	As of December 31, 2013, we consolidate the following VIEs:
	Gulfstar One
	During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar One) in exchange for a 49 percent ownership interest in Gulfstar One. This contribution was based on 49 percent of our estimated cumulative net investment at that time. The $187 million was then distributed to us. Following this transaction, we own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. We, as construction agent for Gulfstar One, are designing, constructing, and installing a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. The project is expected to be in service in the third quarter of 2014. We have received certain advance payments from the producer customers and are committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $325 million, which will be funded with capital contributions from us and the other equity partner, proportional to ownership interest. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One. In December 2013, we committed an additional $134 million to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in 2016. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.
	Constitution
	We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, are building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in late 2015 to 2016 and estimate the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from us and the other equity partners, proportional to ownership interest.

	The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:


		December 31,
		2013			2012			Classification
		(Millions)
	Assets (liabilities):
	Cash and cash equivalents	$	76		$	8		Cash and cash equivalents

	Construction in progress	998			556			Property, plant, and equipment, at cost

	Accounts payable	(120		)	(128		)	Accounts payable - trade
	Construction retainage	(3		)	—			Other accrued liabilities

	Current deferred revenue	(10		)	—			Other accrued liabilities

	Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Regulatory liabilities, deferred income, and other

	Nonconsolidated VIEs
	We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:
	Laurel Mountain
	Our 51 percent-owned equity-method investment in Laurel Mountain is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, we are not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $481 million at December 31, 2013.
	Caiman II
	Our 47.5 percent-owned equity-method investment in Caiman II has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. We are not the primary beneficiary because we do not have the power to direct the activities of Caiman II that most significantly impact its economic performance. At December 31, 2013, the carrying value of our investment in Caiman II was $256 million, which substantially reflects our contributions to that date. In January 2014, we increased our total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date which represents our current maximum exposure to loss related to this investment.

Allocation_of_Net_Income_and_D

Allocation of Net Income and Distributions	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Allocation of Net Income and Distributions	'
	Note 4 – Allocation of Net Income and Distributions
	The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Allocation of net income to general partner:
	Net income	$	1,119		$	1,291		$	1,604

	Net income applicable to pre-partnership operations allocated to general partner	(49		)	(244		)	(226		)
	Net income applicable to noncontrolling interests	(3		)	—			—

	Net costs charged directly to general partner	1			1			(2		)

	Income subject to 2% allocation of general partner interest	1,068			1,048			1,376

	General partner’s share of net income	2		%	2		%	2		%
	General partner’s allocated share of net income before items directly allocable to general partner interest	21			21			28

	Priority allocations, including incentive distributions, paid to general partner (1)	387			355			260

	Net costs charged directly to general partner	(1		)	(1		)	2

	Pre-partnership net income allocated to general partner interest	49			244			226

	Net income allocated to general partner	$	456		$	619		$	516

	Net income	$	1,119		$	1,291		$	1,604

	Net income allocated to general partner	456			619			516

	Net income allocated to noncontrolling interests	3			—			—

	Net income allocated to common limited partners	$	660		$	672		$	1,088

	____________

	-1	The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.
	The Net costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.
	The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):


									General Partner

	Payment Date		Per Unit			Common			2%			Incentive			Total Cash
			Distribution			Units						Distribution			Distribution
												Rights

	2/11/11		$	0.7025		$	204		$	5		$	59		$	268

	5/13/11		0.7175			208			5			63			276

	8/12/11		0.7325			213			6			67			286

	11/11/11		0.7475			217			6			71			294

	2/10/12		0.7625			227			6			78			311

	5/11/12		0.7775			268			8			86			362

	8/10/12		0.7925			274			7			92			373

11/9/12		0.8075			287			8			99			394

2/8/13		0.8275			329			9			104			442

5/10/13		0.8475			351			10			112			473

8/9/13		0.8625			357			11			121			489

11/12/13		0.8775			385			11			46			442

2/13/2014 (1)		0.8925			392			11			153			556

____________

-1	On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014.
The 2012, 2013, and 2014 cash distributions paid to our general partner in the table above have been reduced by $147 million resulting from the temporary waiver of IDRs associated with certain assets acquired in 2012 and an additional $90 million in IDRs waived by our general partner related to the third quarter 2013 distributions, to support our cash distribution metrics as our large platform of growth projects moves toward completion.

Related_Party_Transactions

Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 5 – Related Party Transactions

Reimbursement of Expenses of Our General Partner

The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income.

In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant, and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.

In 2012, Williams engaged a consulting firm to assist in better aligning resources to support their business strategy following the December 31, 2011, spin-off of WPX Energy, Inc. (WPX). Our share of the allocated reorganization-related costs, included in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income, is $2 million and $26 million for the years ended December 31, 2013, and December 31, 2012, respectively.

Transactions with Affiliates and Equity-Method Investees

Product costs, in the Consolidated Statement of Comprehensive Income, include charges for the following types of transactions with affiliates and equity-method investees:

•

Purchases of NGLs for resale from Discovery at market prices at the time of purchase.

•

Payments to OPPL for transportation of NGLs from certain natural gas processing plants.

Transactions with WPX

We consider WPX an affiliate prior to its spin-off from Williams. Revenues, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include the following types of transactions we have with WPX prior to this separation:

•

Revenues from transportation and exchange service and rental of communication facilities with WPX. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly situated nonaffiliated customers.

•

Revenues from gathering, treating, and processing services for WPX under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly situated nonaffiliated customers.

Product costs and Operating and maintenance expenses, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include charges for the following types of transactions we have with WPX prior to this separation:

•

Purchases of NGLs for resale from WPX at market prices at the time of purchase.

•

Purchases of natural gas for shrink replacement and fuel from WPX at market prices at the time of purchase or contract execution.

•

Costs related to a transportation capacity agreement transferred to WPX in a prior year. To the extent that WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs.

Historically, we periodically entered into derivative contracts with WPX to hedge forecasted NGL sales and natural gas purchases. These contracts were priced based on market rates at the time of execution.

Summary of the related party transactions discussed in all sections above.

Years Ended December 31,

2013

2012

2011

(Millions)

Revenues

—

310

Product costs

147

171

728

Operating and maintenance expenses:

Employee costs

339

275

241

Other

—

305

Selling, general, and administrative expenses:

Employee direct costs

270

308

248

Employee allocated costs

169

190

122

The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $13 million and $15 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and December 31, 2012, respectively.

Operating Agreements with Equity-Method Investees

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income are $67 million, $75 million and $57 million for the years ended December 31, 2013, 2012, and 2011, respectively.

Omnibus Agreement

In February 2010, we entered into an omnibus agreement with Williams. Under this agreement, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement. Net amounts received under this agreement for the years ended December 31, 2013, 2012 and 2011 were $12 million, $15 million, and $31 million, respectively.

We have a contribution receivable from our general partner of $3 million and $4 million at December 31, 2013 and December 31, 2012, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against Total partners’ equity in the Consolidated Balance Sheet.

Acquisitions and Equity Issuances

Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the Geismar, Gulfstream, and Canada Acquisitions. Prior to the acquisition, Geismar operations were included in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. In connection with the Geismar Acquisition, the outstanding advances were distributed to Williams at the close of the transaction. The distribution had no impact on our assets or liabilities. Changes in the advances to Williams are presented as Distributions to The Williams Companies, Inc.- net in the Consolidated Statement of Changes in Equity. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within Distributions to/Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.

Note 13 – Partners’ Capital includes related party transactions for the sale of limited partner units to Williams in March 2013 and April 2012.

Board of Directors

A member of Williams’ Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $131 million in Service revenues in Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Mr. H. Michael Krimbill, a member of our Board of Directors until his term completion in August 2012, has served as the Chief Executive Officer of NGL Energy Partners LP, formerly Silverthorne Energy Partners LP, and as a director of its general partner since 2010. We recorded $61 million and $62 million in Product sales in the Consolidated Statement of Comprehensive Income from NGL Energy Partners LP primarily for the sale of propane at market prices and $13 million and $9 million in Product costs in the Consolidated Statement of Comprehensive Income for the purchase of propane at market prices for the years ended December 31, 2012 and 2011, respectively.

Investments

Investments	12 Months Ended
	Dec. 31, 2013
Investments [Abstract]	'
Investments [Text Block]	'
	Note 6 – Investments
	Investments accounted for using the equity method consist of:


		December 31,
		2013				2012
		(Millions)
	OPPL - 50%	$	452			$	454

	Gulfstream - 50%	333				348

	Discovery - 60% (1)	527				350

	Laurel Mountain - 51% (1)	481				444

	Caiman II - 47.5%	256				67

	Other	138				137

		$	2,187			$	1,800

	____________

	-1	We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.
	The difference between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees is $60 million at December 31, 2013, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.
	We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.
	We acquired a 1 percent and 24.5 percent interest in Gulfstream from a subsidiary of Williams in June 2012 and May 2011, respectively. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) We contributed $193 million and $169 million to Discovery in 2013 and 2012, respectively; $42 million, $174 million and $137 million to Laurel Mountain in 2013, 2012, and 2011, respectively; and $192 million and $69 million to Caiman II in 2013 and 2012, respectively.
	Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $154 million, $172 million, and $169 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:


		Years Ended December 31,
		2013				2012				2011
		(Millions)
	Gulfstream	$	81			$	78			$	60

	Discovery	12				21				40

	Aux Sable Liquid Products L.P.	20				28				35

	OPPL	27				28				19


	Summarized Financial Position and Results of Operations of All Equity-Method Investments


		December 31,
		2013				2012
		(Millions)
	Assets (liabilities):
	Current assets	$	412			$	366

	Noncurrent assets	5,956				5,225

	Current liabilities	(264		)		(247		)
	Noncurrent liabilities	(1,305		)		(1,301		)



		Years Ended December 31,
		2013				2012				2011
		(Millions)
	Gross revenue	$	1,333			$	1,213			$	1,242

Operating income	367				378				535

Net income	291				309				460

Other_Income_and_Expense

Other Income and Expense	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Other Income and Expense	'
	Note 7 – Other Income and Expenses
	The following table presents significant gains or losses reflected in Other (income) expense – net within Costs and expenses:


			Years Ended December 31,

			2013			2012			2011
			(Millions)
	Northeast G&P
	Settlement in principle of a producer claim		$	25		$	—		$	—

	Atlantic-Gulf
	Amortization of regulatory asset associated with asset retirement obligations		30			7			6

	Write-off of the Eminence abandonment regulatory asset not recoverable through rates		12			—			—

	Insurance recoveries associated with the Eminence abandonment		(16		)	—			—

	Project feasibility costs		4			21			10

	Capitalization of project feasibility costs previously expensed		(1		)	(19		)	(11		)
	NGL & Petchem Services
	Net insurance recoveries associated with the Geismar Incident		(40		)	—			—


	The reversals of project feasibility costs from expense to capital are associated with natural gas pipeline expansion projects. These reversals were made upon determining that the related projects were probable of development. These costs are now included in the capital costs of the projects, which we believe are probable of recovery through the project rates.
	On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.
	We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:

	•	Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;

	•	General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

	•	Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.
	We have expensed $13 million at NGL & Petchem Services during 2013 of costs under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through December 31, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million gain included in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income.
	Additional Item
	We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $3 million, $2 million, and $15 million of charges to Operating and maintenance expenses at Atlantic-Gulf during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

Provision_Benefit_for_Income_T

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	Note 8 – Provision (Benefit) for Income Taxes
	The Provision (benefit) for income taxes includes:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Current:
	State	$	2		$	11		$	3

	Foreign	(22		)	26			32

		(20		)	37			35

	Deferred:
	State	15			—			—

	Foreign	35			5			11

		50			5			11

	Total provision (benefit)	$	30		$	42		$	46

	Reconciliations from the Provision (benefit) for income taxes at the federal statutory rate to the recorded Provision (benefit) for income taxes are as follows:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision at statutory rate	$	402		$	467		$	577

	Increases (decreases) in taxes resulting from:
	Income not subject to federal tax	(402		)	(467		)	(577		)
	State income taxes	17			11			3

	Foreign operations — net	13			31			43

	Provision (benefit) for income taxes	$	30		$	42		$	46

	The 2013 state deferred provision includes $15 million related to the impact of a second-quarter 2013 Texas franchise tax law change.
	Income before income taxes includes $61 million, $96 million, and $136 million of foreign income in 2013, 2012, and 2011, respectively.
	Deferred tax liabilities, attributable to the taxable temporary differences from property, plant, and equipment, were $117 million and $72 million in 2013 and 2012, respectively.
	Cash payments for income taxes (net of refunds) were $2 million, $54 million, and $35 million in 2013, 2012, and 2011, respectively.
	As of December 31, 2013, we do not have any material unrecognized tax benefits.
	Tax years after 2009 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2007. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition.

Benefit_Plans

Benefit Plans	12 Months Ended
Benefit Plans	Dec. 31, 2013
Employee Benefits and Share-based Compensation [Abstract]	'
Pension and Other Postretirement Benefits Disclosure [Text Block]	'
	Note 9 – Benefit Plans
	Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.
	Defined Benefit Pension plans
	Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2013, 2012, and 2011 totaled $44 million, $41 million, and $32 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.4 billion and $1.5 billion at December 31, 2013 and 2012, respectively. The plans were underfunded by $143 million and $478 million at December 31, 2013 and 2012, respectively.
	Postretirement benefits other than pensions
	Williams provides certain retiree health care and life insurance benefits for eligible participants. Generally, employees that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries are eligible for subsidized retiree medical benefits. The cost charged to us for the plans anticipates future cost-sharing that is consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. We recognized a net periodic postretirement benefit credited to us by Williams of $4 million in 2013 and $2 million in 2011, and a net periodic postretirement benefit cost charged to us by Williams of $4 million in 2012. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $213 million and $331 million at December 31, 2013 and 2012, respectively. The plans were underfunded by $12 million and $156 million at December 31, 2013 and 2012, respectively.
	Any differences between the annual expense and amounts currently being recovered in rates by our FERC-regulated gas pipelines are recorded as an adjustment to expense and collected or refunded through future rate adjustments.
	Defined contribution plans
	Williams charged us compensation expense of $16 million, $19 million, and $17 million in 2013, 2012, and 2011, respectively, for Williams’ contributions to these plans.
	Employee Stock-Based Compensation Plan information
	The Williams Companies, Inc. 2007 Incentive Plan (Plan) provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
	Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.
	Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $12 million, $13 million and $11 million, respectively.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Inventories	'
	Note 10 – Inventories


		December 31,

		2013		2012

		(Millions)

	Natural gas liquids, olefins, and natural gas in underground storage	$	111	$	97

	Materials, supplies, and other	83		78

		$	194	$	175

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment [Textblock]	'
	Note 11 – Property, Plant and Equipment


		Estimated		Depreciation
		Useful Life (1)		Rates (1)	December 31,
		(Years)		(%)	2013			2012
					(Millions)
	Nonregulated:
	Natural gas gathering and processing facilities	5 - 40			$	9,172		$	7,694

	Construction in progress	Not applicable			2,727			1,870

	Other	3 - 45			964			780

	Regulated:
	Natural gas transmission facilities			1.2 - 6.97	10,633			9,963

	Construction in progress			Not applicable	273			337

	Other			1.35 - 33.33	1,293			1,418

	Total property, plant, and equipment, at cost				$	25,062		$	22,062

	Accumulated depreciation and amortization				(7,437		)	(6,906		)
	Property, plant, and equipment — net				$	17,625		$	15,156

	______________________

	-1	Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.
	Depreciation and amortization expense for Property, plant, and equipment – net was $729 million, $690 million and $634 million in 2013, 2012, and 2011, respectively.
	Regulated Property, plant, and equipment – net includes approximately $785 million and $825 million at December 31, 2013 and 2012, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
	Asset Retirement Obligations
	Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation and compression facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
	The following table presents the significant changes to our asset retirement obligations (ARO):


		December 31,
		2013			2012
		(Millions)
	Beginning balance	$	579		$	573

	Liabilities incurred	8			8

	Liabilities settled (1)	(31		)	(44		)
	Accretion expense	53			43

	Revisions (2)	(48		)	(1		)
	Ending balance	$	561		$	579

	______________

	-1	For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.


	-2	Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

	Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

Debt_Banking_Arrangements_and_

Debt, Banking Arrangements, and Leases	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt Disclosure [Text Block]	'
	Note 12 – Debt, Banking Arrangements, and Leases
	Long-Term Debt


			December 31,
			2013			2012
			(Millions)
	Unsecured:
	Transco:
	6.4% Notes due 2016		$	200		$	200

	6.05% Notes due 2018		250			250

	7.08% Debentures due 2026		8			8

	7.25% Debentures due 2026		200			200

	5.4% Notes due 2041		375			375

	4.45% Notes due 2042		400			400

	Northwest Pipeline:
	7% Notes due 2016		175			175

	5.95% Notes due 2017		185			185

	6.05% Notes due 2018		250			250

	7.125% Debentures due 2025		85			85

	Williams Partners L.P.:
	3.8% Notes due 2015		750			750

	7.25% Notes due 2017		600			600

	5.25% Notes due 2020		1,500			1,500

	4.125% Notes due 2020		600			600

	4% Notes due 2021		500			500

	3.35% Notes due 2022		750			750

	4.5% Notes due 2023		600			—

	6.3% Notes due 2040		1,250			1,250

	5.8% Notes due 2043		400			—

	Credit facility loans		—			375

	Unamortized debt discount		(21		)	(16		)
	Long-term debt		$	9,057		$	8,437

	The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.
	The following table presents aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years:


		December 31,
		2013
		(Millions)
	2014	$	—

2015	750

2016	375

2017	785

2018	500


Issuances and retirements
In November 2013, we completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our senior unsecured revolving credit facility and for general partnership purposes.
In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012. A portion of the proceeds from the issuance of these notes was used to repay Transco’s $325 million of 8.875 percent senior unsecured notes that matured on July 15, 2012.

Credit Facility
In July 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by the other co-borrowers. Our credit facility may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements. At December 31, 2013, letter of credit capacity under our $2.5 billion credit facility is $1.3 billion, no letters of credit have been issued, and no loans are outstanding under our credit facility.
Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2013, we are in compliance with these financial covenants.
The credit agreement governing our credit facility contains the following terms and conditions:

•	Each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.175 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

•	Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.

•	If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.
Commercial Paper Program
In March 2013, we initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. We classify commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2013, have maturity dates less than three months from the date of issuance. At December 31, 2013, $225 million of Commercial paper is outstanding at a weighted average interest rate of 0.42 percent.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $366 million in 2013, $381 million in 2012, and $387 million in 2011.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:


	December 31,
	2013
	(Millions)
2014	$	42

2015	36

2016	35

2017	31

2018	29

Thereafter	123

Total	$	296

Under our right-of-way agreement with the Jicarilla Apache Nation, we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.
Total rent expense was $51 million in 2013, $46 million in 2012, and $38 million in 2011.

Partners_Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2013
Partners' Capital Notes [Abstract]	'
Unit Transactions Disclosure [Text Block]	'
	Note 13 – Partners’ Capital
	At December 31, 2013 and 2012, the public held 36 percent and 30 percent, respectively, of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2013 and 2012 are summarized below.
	In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.
	In August 2013, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures and for general partnership purposes.
	In January 2012, we issued 7,000,000 common units. The net proceeds of approximately $426 million were used to fund capital expenditures and for other partnership purposes.
	In February 2012, we closed the Laser Acquisition. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
	In February 2012, the underwriters exercised their option to purchase an additional 1,050,000 common units pursuant to our common unit offering in January 2012. The net proceeds of approximately $64 million were used for general partnership purposes.
	In April 2012, we issued 10,000,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 973,368 common units. The net proceeds of approximately $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) We also used $1 billion in proceeds from an April 2012 sale of 16,360,133 common units to Williams to partially fund the Caiman Acquisition.
	In April 2012, we closed the Caiman Acquisition. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)
	In June 2012, we acquired a 1 percent interest in Gulfstream from a subsidiary of Williams. In connection with this transaction, we issued 238,050 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
	In August 2012, we completed an equity issuance of 8,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 1,275,000 common units. The net proceeds of approximately $488 million were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.
	In November 2012, we closed the Geismar Acquisition with Williams. In connection with this transaction, we issued 42,778,812 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
	Limited Partners’ Rights
	Significant rights of the limited partners include the following:

	•	Right to receive distributions of available cash within 45 days after the end of each quarter.

	•	No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.

	•	The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.
	Incentive Distribution Rights
	Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:


	Quarterly Distribution Target Amount (per unit)		Unitholders	General
				Partner
	Minimum quarterly distribution of $0.35		98%	2%
	Up to $0.4025		98	2
	Above $0.4025 up to $0.4375		85	15
	Above $0.4375 up to $0.5250		75	25
	Above $0.5250		50	50
	See Note 4 – Allocation of Net Income and Distributions for information regarding IDR waivers.
	In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
	Issuances of Additional Partnership Securities
	Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

	The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


									Fair Value Measurements Using
		Carrying				Fair			Quoted		Significant			Significant
		Amount				Value			Prices In		Other			Unobservable
									Active		Observable			Inputs
									Markets for		Inputs			(Level 3)
									Identical		(Level 2)
									Assets
									(Level 1)
		(Millions)
	Assets (liabilities) at December 31, 2013:
	Measured on a recurring basis:
	ARO Trust investments	$	33			$	33		$	33	$	—		$	—

	Energy derivatives assets not designated as hedging instruments	3				3			—		—			3

	Energy derivatives liabilities not designated as hedging instruments	(3		)		(3		)	—		(1		)	(2		)

	Additional disclosures:
	Notes receivable and other	7				7			1		6			—

	Long-term debt	(9,057		)		(9,581		)	—		(9,581		)	—

	Assets (liabilities) at December 31, 2012:
	Measured on a recurring basis:
	ARO Trust investments	$	18			$	18		$	18	$	—		$	—

	Energy derivatives assets not designated as hedging instruments	5				5			—		—			5

	Energy derivatives liabilities not designated as hedging instruments	(1		)		(1		)	—		—			(1		)

	Additional disclosures:
	Notes receivable and other	11				10			2		8			—

	Long-term debt	(8,437		)		(9,624		)	—		(9,624		)	—


	Fair Value Methods
	We use the following methods and assumptions in estimating the fair value of our financial instruments:
	Assets and liabilities measured at fair value on a recurring basis
	ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
	Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
	Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2013 or 2012.
	Additional fair value disclosures
	Notes receivable and other: The disclosed fair value of our notes receivable is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade accounts and notes receivable, net, and the noncurrent portion is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.
	Long-term debt: The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
	Guarantees
	We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
	Concentration of Credit Risk
	Cash equivalents
	Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
	Accounts and notes receivable
	The following table summarizes concentration of receivables, net of allowances.


		December 31,
		2013				2012
		(Millions)
	NGLs, natural gas, and related products and services	$	341			$	406

Transportation of natural gas and related products	193				169

Other	34				14

Total	$	568			$	589

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Revenues
In 2013, 2012 and 2011, we had one customer in our NGL & Petchem Services segment that accounted for 9 percent, 14 percent, and 17 percent of our consolidated revenues, respectively.

Contingent_Liabilities

Contingent Liabilities	12 Months Ended
Contingent Liabilities	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Contingent Liabilities	'
	Note 15 – Contingent Liabilities and Commitments

	Environmental Matters
	We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2013, we have accrued liabilities totaling $20 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.
	The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
	Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2013, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.
	We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2013, we have accrued liabilities totaling $7 million for these costs.
	Geismar Incident
	As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including affiliate employees and contractors) reported injuries, which varied from minor to serious. We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations. On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued Citations for the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citation. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.
	Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.
	Rate Matters
	On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million, in Other accrued liabilities, which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.
	Other
	In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
	Summary

	We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. We disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.
	Commitments
	Commitments for construction and acquisition of property, plant and equipment are approximately $1.4 billion at December 31, 2013.

Segment_Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Disclosures	'
	Note 16 – Segment Disclosures
	Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
	Performance Measurement
	We currently evaluate segment operating performance based on Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, Equity earnings (losses) and Income (loss) from investments. General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business and are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
	The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location.


				United States				Canada				Total
				(Millions)
	Revenues from external customers:
		2013		$	6,685			$	150			$	6,835

		2012		7,320				151				7,471

		2011		7,714				202				7,916


	Long-lived assets:
		2013		$	18,776			$	1,137			$	19,913

		2012		16,637				870				17,507

		2011		11,866				583				12,449

	Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.

	The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.


		Northeast				Atlantic-				West				NGL &				Eliminations				Total
		G&P				Gulf								Petchem
														Services
		(Millions)

	2013
	Segment revenues:

	Service revenues

	External	$	335			$	1,414			$	1,053			$	112			$	—			$	2,914

	Internal	—				10				1				—				(11		)		—

	Total service revenues	335				1,424				1,054				112				(11		)		2,914

	Product sales
	External	166				830				64				2,861				—				3,921

	Internal	—				95				708				294				(1,097		)		—

	Total product sales	166				925				772				3,155				(1,097		)		3,921

	Total revenues	$	501			$	2,349			$	1,826			$	3,267			$	(1,108	)		$	6,835

	Segment profit (loss)	$	(24	)		$	614			$	741			$	346							$	1,677

	Less:
	Equity earnings (losses)	(7		)		72				—				39								104

	Income (loss) from investments	—				—				—				(3		)						(3		)

	Segment operating income (loss)	$	(17	)		$	542			$	741			$	310							1,576

General corporate expenses																					(169		)
Operating income																					$	1,407


Other financial information:
Depreciation and amortization	$	132			$	363			$	236			$	60			$	—			$	791


2012
Segment revenues:
Service revenues
External	$	168			$	1,371			$	1,067			$	108			$	—			$	2,714

Internal	—				12				5				—				(17		)		—

Total service revenues	168				1,383				1,072				108				(17		)		2,714

Product sales
External	2				709				40				4,006				—				4,757

Internal	—				363				1,089				258				(1,710		)		—

Total product sales	2				1,072				1,129				4,264				(1,710		)		4,757

Total revenues	$	170			$	2,455			$	2,201			$	4,372			$	(1,727	)		$	7,471

Segment profit (loss)	$	(37	)		$	574			$	980			$	390							$	1,907

Less:
Equity earnings (losses)	(23		)		92				—				42								111

Income (loss) from investments	—				—				—				(4		)						(4		)

Segment operating income (loss)	$	(14	)		$	482			$	980			$	352							1,800

General corporate expenses																					(190		)
Operating income																					$	1,610


Other financial information:
Depreciation and amortization	$	76			$	381			$	234			$	43			$	—			$	734





	Northeast				Atlantic-				West				NGL &				Eliminations				Total
	G&P				Gulf								Petchem
													Services
	(Millions)

2011
Segment revenues:
Service revenues
External	$	49			$	1,332			$	1,053			$	84			$	—			$	2,518

Internal	—				—				4				—				(4		)		—

Total service revenues	49				1,332				1,057				84				(4		)		2,518

Product sales
External	—				606				11				4,781				—				5,398

Internal	—				531				1,622				56				(2,209		)		—

Total product sales	—				1,137				1,633				4,837				(2,209		)		5,398

Total revenues	$	49			$	2,469			$	2,690			$	4,921			$	(2,213	)		$	7,916

Segment profit (loss)	$	23			$	585			$	1,181			$	385							$	2,174

Less:
Equity earnings (losses)	(1		)		90				—				53								142

Income (loss) from investments	—				—				—				(4		)						(4		)

Segment operating income (loss)	$	24			$	495			$	1,181			$	336							2,036

General corporate expenses																					(122		)
Operating income																					$	1,914


Other financial information:
Depreciation and amortization	$	5			$	365			$	236			$	31			$	—			$	637


The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:


	Total Assets at December 31,								Investments at December 31,								Additions to Long-Lived Assets at December 31,
	2013				2012				2013				2012				2013				2012				2011
	(Millions)
Northeast G&P (1)	$	6,229			$	4,745			$	737			$	511			$	1,376			$	3,909			$	204

Atlantic-Gulf	10,007				8,734				930				774				1,072				1,002				650

West	4,767				4,688				—				—				210				360				301

NGL & Petchem Services	3,035				2,469				520				515				746				571				314

Other corporate assets	147				409				—				—				5				16				25

Eliminations (2)	(614		)		(367		)		—				—				—				—				—

Total	$	23,571			$	20,678			$	2,187			$	1,800			$	3,409			$	5,858			$	1,494





-1	2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)


-2	Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

Subsequent_Events_Notes

Subsequent Events (Notes)	12 Months Ended
Subsequent Events (Notes)	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events [Text Block]	'
	Note 17 – Subsequent Events

	In March 2014 we completed a registered offering of debt securities consisting of $1 billion of 4.3 percent senior notes due 2024 and $500 million of 5.4 percent senior notes due 2044. The proceeds were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

	As of May 19, 2014, $370 million is outstanding under our commercial paper program.

Description_of_Business_Basis_

Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Principles of consolidation	'
	Principles of consolidation
	The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:


	•	Determining whether an entity is a variable interest entity (VIE);


	•	Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;


	•	Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;


	•	Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

	We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.
Common control transactions	'
	Common control transactions
	Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.
Use of estimates	'
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
	Significant estimates and assumptions include:

	•	Impairment assessments of investments, property, plant, and equipment, goodwill and other identifiable intangible assets;

	•	Litigation-related contingencies;

	•	Environmental remediation obligations;

	•	Asset retirement obligations;

	•	Acquisition related purchase price allocations.

	These estimates are discussed further throughout these notes.
Regulatory Accounting	'
	Regulatory accounting
	Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for non regulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:


		December 31,

		2013		2012

		(Millions)

	Current assets reported within Other current assets	$	39	$	39

	Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275

	Total regulated assets	$	354	$	314



	Current liabilities reported within Other accrued liabilities	$	19	$	15

	Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250

	Total regulated liabilities	$	308	$	265



Cash and cash equivalents	'
	Cash and cash equivalents
	Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Accounts receivable	'
	Accounts receivable
	Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventory valuation	'
	Inventory valuation
	All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment	'
	Property, plant, and equipment
	Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
	As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (See Note 11 – Property, Plant and Equipment.)
	Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income.
	Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
	We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.
	Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill	'
	Goodwill
	Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.
Other intangible assets	'
	Other intangible assets
	Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets and investments	'
	Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
	We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
	For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
	We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
	Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Contingent liabilities	'
	Contingent liabilities
	We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facilities and commercial paper program	'
	Cash flows from revolving credit facility and commercial paper program
	Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt, Banking Arrangements, and Leases.)
Derivative instruments and hedging activities	'
	Derivative instruments and hedging activities
	We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 14 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.
	The accounting for the changes in fair value of a commodity derivative can be summarized as follows:


	Derivative Treatment		Accounting Method
	Normal purchases and normal sales exception		Accrual accounting
	Designated in a qualifying hedging relationship		Hedge accounting
	All other derivatives		Mark-to-market accounting
	We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
	We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.
	For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.
	For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.
	Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.
	Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Revenues	'
	Revenues
	As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.
	Service revenues
	Revenues include services pursuant to long-term firm transportation and storage agreements within our interstate natural gas pipeline businesses. These agreements provide for a reservation charge based on the volume of a contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services, and storage injection and withdrawal services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
	Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
	Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

	Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
	Product sales
	In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.
	We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.
	Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
	Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.
	Our Canadian business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are sold and delivered.
Interest capitalized	'
	Interest capitalized
	We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating income in the Consolidated Statement of Comprehensive Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Income taxes	'
	Income taxes
	We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations. Other income taxes on net income are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.
	Foreign deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings per unit	'
	Earnings per unit
	We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.
Pension and other postretirement benefits	'
	Pension and other postretirement benefits
	We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 9 – Benefit Plans.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
Foreign Currency Translation	'
	Foreign currency translation
	Our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI.
	Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Comprehensive Income.
	Accumulated Other Comprehensive Income (Loss)
	AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income in any of the periods presented.

General_Description_of_Busines

General, Description of Business, Basis of Presentation and Summary of Significant Accounting Policies General, Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Schedule of Regulatory Assets and Liabilities [Text Block]	'
	Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:


		December 31,

		2013		2012

		(Millions)

	Current assets reported within Other current assets	$	39	$	39

	Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275

	Total regulated assets	$	354	$	314



	Current liabilities reported within Other accrued liabilities	$	19	$	15

	Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250

	Total regulated liabilities	$	308	$	265

Acquisitions_Goodwill_and_Othe1

Acquisitions Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	'
	The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Northeast G&P segment:


		Laser			Caiman
		(Millions)
	Assets held-for-sale	$	18		$	—

	Other current assets	3			16

	Property, plant, and equipment	158			656

	Intangible assets:
	Customer contracts	316			1,141

	Customer relationships	—			250

	Other	2			2

	Current liabilities	(21		)	(94		)
	Noncurrent liabilities	—			(3		)

	Identifiable net assets acquired	476			1,968

	Goodwill	290			356

		$	766		$	2,324

Schedule of Finite-Lived Intangible Assets [Table Text Block]	'
	The gross carrying amount and accumulated amortization of Other intangible assets at December 31 are as follows:


		2013						2012
		Gross Carrying Amount			Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
		(Millions)
	Customer contracts	$	1,493		$	(88	)	$	1,493	$	(38	)

	Customer relationships	250			(14		)	250		(6		)

	Other	4			(3		)	4		(1		)

	Total	$	1,747		$	(105	)	$	1,747	$	(45	)

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2013
Variable Interest Entity Disclosures [Abstract]	'
Schedule of Variable Interest Entities [Table Text Block]	'
	The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:


		December 31,
		2013			2012			Classification
		(Millions)
	Assets (liabilities):
	Cash and cash equivalents	$	76		$	8		Cash and cash equivalents

	Construction in progress	998			556			Property, plant, and equipment, at cost

	Accounts payable	(120		)	(128		)	Accounts payable - trade
	Construction retainage	(3		)	—			Other accrued liabilities

	Current deferred revenue	(10		)	—			Other accrued liabilities

	Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Regulatory liabilities, deferred income, and other

Allocation_of_Net_Income_and_D1

Allocation of Net Income and Distributions (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Allocation of net income among our general partner, limited partners, and noncontrolling interests	'
	The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Allocation of net income to general partner:
	Net income	$	1,119		$	1,291		$	1,604

	Net income applicable to pre-partnership operations allocated to general partner	(49		)	(244		)	(226		)
	Net income applicable to noncontrolling interests	(3		)	—			—

	Net costs charged directly to general partner	1			1			(2		)

	Income subject to 2% allocation of general partner interest	1,068			1,048			1,376

	General partner’s share of net income	2		%	2		%	2		%
	General partner’s allocated share of net income before items directly allocable to general partner interest	21			21			28

	Priority allocations, including incentive distributions, paid to general partner (1)	387			355			260

	Net costs charged directly to general partner	(1		)	(1		)	2

	Pre-partnership net income allocated to general partner interest	49			244			226

	Net income allocated to general partner	$	456		$	619		$	516

	Net income	$	1,119		$	1,291		$	1,604

	Net income allocated to general partner	456			619			516

	Net income allocated to noncontrolling interests	3			—			—

	Net income allocated to common limited partners	$	660		$	672		$	1,088

	____________

	-1	The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.
Authorized payment of cash distributions	'
	The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):


									General Partner

	Payment Date		Per Unit			Common			2%		Incentive		Total Cash
			Distribution			Units					Distribution		Distribution
											Rights

	2/11/11		$	0.7025		$	204		$	5	$	59	$	268

	5/13/11		0.7175			208			5		63		276

	8/12/11		0.7325			213			6		67		286

	11/11/11		0.7475			217			6		71		294

	2/10/12		0.7625			227			6		78		311

	5/11/12		0.7775			268			8		86		362

	8/10/12		0.7925			274			7		92		373

	11/9/12		0.8075			287			8		99		394

	2/8/13		0.8275			329			9		104		442

	5/10/13		0.8475			351			10		112		473

	8/9/13		0.8625			357			11		121		489

	11/12/13		0.8775			385			11		46		442

	2/13/2014 (1)		0.8925			392			11		153		556

	____________

	-1	On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions [Table Text Block]	'
	Summary of the related party transactions discussed in all sections above.


		Years Ended December 31,
		2013		2012		2011
		(Millions)
	Revenues	$	—	$	—	$	310

	Product costs	147		171		728

	Operating and maintenance expenses:

	Employee costs	339		275		241

	Other	—		—		305

	Selling, general, and administrative expenses:
	Employee direct costs	270		308		248

	Employee allocated costs	169		190		122

Investments_Tables

Investments (Tables)	12 Months Ended
	Dec. 31, 2013
Investments [Abstract]	'
Investments [Table Text Block]	'
	Investments accounted for using the equity method consist of:


		December 31,
		2013			2012
		(Millions)
	OPPL - 50%	$	452		$	454

	Gulfstream - 50%	333			348

	Discovery - 60% (1)	527			350

	Laurel Mountain - 51% (1)	481			444

	Caiman II - 47.5%	256			67

	Other	138			137

		$	2,187		$	1,800

	____________

	-1	We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.
Dividends and distributions [Table Text Block]	'


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Gulfstream	$	81		$	78		$	60

	Discovery	12			21			40

	Aux Sable Liquid Products L.P.	20			28			35

	OPPL	27			28			19

Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block]	'
	Summarized Financial Position and Results of Operations of All Equity-Method Investments


		December 31,
		2013			2012
		(Millions)
	Assets (liabilities):
	Current assets	$	412		$	366

	Noncurrent assets	5,956			5,225

	Current liabilities	(264		)	(247		)
	Noncurrent liabilities	(1,305		)	(1,301		)



		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Gross revenue	$	1,333		$	1,213		$	1,242

	Operating income	367			378			535

	Net income	291			309			460

Other_Income_and_Expense_Table

Other Income and Expense (Tables)	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	'
	The following table presents significant gains or losses reflected in Other (income) expense – net within Costs and expenses:


		Years Ended December 31,

		2013			2012			2011
		(Millions)
	Northeast G&P
	Settlement in principle of a producer claim	$	25		$	—		$	—

	Atlantic-Gulf
	Amortization of regulatory asset associated with asset retirement obligations	30			7			6

	Write-off of the Eminence abandonment regulatory asset not recoverable through rates	12			—			—

	Insurance recoveries associated with the Eminence abandonment	(16		)	—			—

	Project feasibility costs	4			21			10

	Capitalization of project feasibility costs previously expensed	(1		)	(19		)	(11		)
	NGL & Petchem Services
	Net insurance recoveries associated with the Geismar Incident	(40		)	—			—

Provision_Benefit_for_Income_T1

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The Provision (benefit) for income taxes includes:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Current:
	State	$	2		$	11		$	3

	Foreign	(22		)	26			32

		(20		)	37			35

	Deferred:
	State	15			—			—

	Foreign	35			5			11

		50			5			11

	Total provision (benefit)	$	30		$	42		$	46

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	Reconciliations from the Provision (benefit) for income taxes at the federal statutory rate to the recorded Provision (benefit) for income taxes are as follows:


		Years Ended December 31,
		2013			2012			2011
		(Millions)
	Provision at statutory rate	$	402		$	467		$	577

	Increases (decreases) in taxes resulting from:
	Income not subject to federal tax	(402		)	(467		)	(577		)
	State income taxes	17			11			3

	Foreign operations — net	13			31			43

	Provision (benefit) for income taxes	$	30		$	42		$	46

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Inventories	'


		December 31,

		2013		2012

		(Millions)

	Natural gas liquids, olefins, and natural gas in underground storage	$	111	$	97

	Materials, supplies, and other	83		78

		$	194	$	175

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Propertyl, Plant, and Equipment [Table Text Block]	'


		Estimated		Depreciation
		Useful Life (1)		Rates (1)	December 31,
		(Years)		(%)	2013			2012
					(Millions)
	Nonregulated:
	Natural gas gathering and processing facilities	5 - 40			$	9,172		$	7,694

	Construction in progress	Not applicable			2,727			1,870

	Other	3 - 45			964			780

	Regulated:
	Natural gas transmission facilities			1.2 - 6.97	10,633			9,963

	Construction in progress			Not applicable	273			337

	Other			1.35 - 33.33	1,293			1,418

	Total property, plant, and equipment, at cost				$	25,062		$	22,062

	Accumulated depreciation and amortization				(7,437		)	(6,906		)
	Property, plant, and equipment — net				$	17,625		$	15,156

	______________________

	-1	Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.
Asset Retirement Obligation [Table Text Block]	'


		December 31,
		2013			2012
		(Millions)
	Beginning balance	$	579		$	573

	Liabilities incurred	8			8

	Liabilities settled (1)	(31		)	(44		)
	Accretion expense	53			43

	Revisions (2)	(48		)	(1		)
	Ending balance	$	561		$	579

	______________

	-1	For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.


	-2	Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

Debt_Banking_Arrangements_and_1

Debt, Banking Arrangements, and Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Long-term Debt Instruments [Table Text Block]	'
	Long-Term Debt


			December 31,
			2013			2012
			(Millions)
	Unsecured:
	Transco:
	6.4% Notes due 2016		$	200		$	200

	6.05% Notes due 2018		250			250

	7.08% Debentures due 2026		8			8

	7.25% Debentures due 2026		200			200

	5.4% Notes due 2041		375			375

	4.45% Notes due 2042		400			400

	Northwest Pipeline:
	7% Notes due 2016		175			175

	5.95% Notes due 2017		185			185

	6.05% Notes due 2018		250			250

	7.125% Debentures due 2025		85			85

	Williams Partners L.P.:
	3.8% Notes due 2015		750			750

	7.25% Notes due 2017		600			600

	5.25% Notes due 2020		1,500			1,500

	4.125% Notes due 2020		600			600

	4% Notes due 2021		500			500

	3.35% Notes due 2022		750			750

	4.5% Notes due 2023		600			—

	6.3% Notes due 2040		1,250			1,250

	5.8% Notes due 2043		400			—

	Credit facility loans		—			375

	Unamortized debt discount		(21		)	(16		)
	Long-term debt		$	9,057		$	8,437

Schedule of Maturities of Long-term Debt [Table Text Block]	'
	The following table presents aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years:


		December 31,
		2013
		(Millions)
	2014	$	—

	2015	750

	2016	375

	2017	785

	2018	500

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	'
	The future minimum annual rentals under noncancelable operating leases, are payable as follows:


		December 31,
		2013
		(Millions)
	2014	$	42

	2015	36

	2016	35

	2017	31

	2018	29

	Thereafter	123

	Total	$	296

Partners_Capital_Tables

Partners' Capital (Tables)	12 Months Ended
Partners' Capital (Tables)	Dec. 31, 2013
Partners' Capital Notes [Abstract]	'
Incentive Distribution Percentage By Specified Target Level [Table Text Block]	'
	Incentive Distribution Rights
	Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:


	Quarterly Distribution Target Amount (per unit)	Unitholders	General
	Quarterly Distribution Target Amount (per unit)	Unitholders	Partner
	Minimum quarterly distribution of $0.35	98%	2%
	Up to $0.4025	98	2
	Above $0.4025 up to $0.4375	85	15
	Above $0.4375 up to $0.5250	75	25
	Above $0.5250	50	50

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'


								Fair Value Measurements Using
		Carrying			Fair			Quoted		Significant			Significant
		Amount			Value			Prices In		Other			Unobservable
								Active		Observable			Inputs
								Markets for		Inputs			(Level 3)
								Identical		(Level 2)
								Assets
								(Level 1)
		(Millions)
	Assets (liabilities) at December 31, 2013:
	Measured on a recurring basis:
	ARO Trust investments	$	33		$	33		$	33	$	—		$	—

	Energy derivatives assets not designated as hedging instruments	3			3			—		—			3

	Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)

	Additional disclosures:
	Notes receivable and other	7			7			1		6			—

	Long-term debt	(9,057		)	(9,581		)	—		(9,581		)	—

	Assets (liabilities) at December 31, 2012:
	Measured on a recurring basis:
	ARO Trust investments	$	18		$	18		$	18	$	—		$	—

	Energy derivatives assets not designated as hedging instruments	5			5			—		—			5

	Energy derivatives liabilities not designated as hedging instruments	(1		)	(1		)	—		—			(1		)

	Additional disclosures:
	Notes receivable and other	11			10			2		8			—

	Long-term debt	(8,437		)	(9,624		)	—		(9,624		)	—

Concentration of receivables, net of allowances, by product or service	'
	The following table summarizes concentration of receivables, net of allowances.


		December 31,
		2013			2012
		(Millions)
	NGLs, natural gas, and related products and services	$	341		$	406

	Transportation of natural gas and related products	193			169

	Other	34			14

	Total	$	568		$	589

Segment_Disclosures_Tables

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of Revenue from External Customers and Long-Lived Assets, by Geographical Areas [Table Text Block]	'
	The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location.


				United States				Canada				Total
				(Millions)
	Revenues from external customers:
		2013		$	6,685			$	150			$	6,835

		2012		7,320				151				7,471

		2011		7,714				202				7,916


	Long-lived assets:
		2013		$	18,776			$	1,137			$	19,913

		2012		16,637				870				17,507

		2011		11,866				583				12,449

	Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
Reconciliation of segment revenues and segment profit (loss) [Table Text Block]	'
	The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.


		Northeast				Atlantic-				West				NGL &				Eliminations				Total
		G&P				Gulf								Petchem
														Services
		(Millions)

	2013
	Segment revenues:

	Service revenues

	External	$	335			$	1,414			$	1,053			$	112			$	—			$	2,914

	Internal	—				10				1				—				(11		)		—

	Total service revenues	335				1,424				1,054				112				(11		)		2,914

	Product sales
	External	166				830				64				2,861				—				3,921

	Internal	—				95				708				294				(1,097		)		—

	Total product sales	166				925				772				3,155				(1,097		)		3,921

	Total revenues	$	501			$	2,349			$	1,826			$	3,267			$	(1,108	)		$	6,835

	Segment profit (loss)	$	(24	)		$	614			$	741			$	346							$	1,677

	Less:
	Equity earnings (losses)	(7		)		72				—				39								104

	Income (loss) from investments	—				—				—				(3		)						(3		)

	Segment operating income (loss)	$	(17	)		$	542			$	741			$	310							1,576

	General corporate expenses																					(169		)
	Operating income																					$	1,407


	Other financial information:
	Depreciation and amortization	$	132			$	363			$	236			$	60			$	—			$	791


	2012
	Segment revenues:
	Service revenues
	External	$	168			$	1,371			$	1,067			$	108			$	—			$	2,714

	Internal	—				12				5				—				(17		)		—

	Total service revenues	168				1,383				1,072				108				(17		)		2,714

	Product sales
	External	2				709				40				4,006				—				4,757

	Internal	—				363				1,089				258				(1,710		)		—

	Total product sales	2				1,072				1,129				4,264				(1,710		)		4,757

	Total revenues	$	170			$	2,455			$	2,201			$	4,372			$	(1,727	)		$	7,471

Segment profit (loss)	$	(37	)		$	574			$	980			$	390							$	1,907

Less:
Equity earnings (losses)	(23		)		92				—				42								111

Income (loss) from investments	—				—				—				(4		)						(4		)

Segment operating income (loss)	$	(14	)		$	482			$	980			$	352							1,800

General corporate expenses																					(190		)
Operating income																					$	1,610


Other financial information:
Depreciation and amortization	$	76			$	381			$	234			$	43			$	—			$	734





	Northeast				Atlantic-				West				NGL &				Eliminations				Total
	G&P				Gulf								Petchem
													Services
	(Millions)

2011
Segment revenues:
Service revenues
External	$	49			$	1,332			$	1,053			$	84			$	—			$	2,518

Internal	—				—				4				—				(4		)		—

Total service revenues	49				1,332				1,057				84				(4		)		2,518

Product sales
External	—				606				11				4,781				—				5,398

Internal	—				531				1,622				56				(2,209		)		—

Total product sales	—				1,137				1,633				4,837				(2,209		)		5,398

Total revenues	$	49			$	2,469			$	2,690			$	4,921			$	(2,213	)		$	7,916

Segment profit (loss)	$	23			$	585			$	1,181			$	385							$	2,174

Less:
Equity earnings (losses)	(1		)		90				—				53								142

Income (loss) from investments	—				—				—				(4		)						(4		)

Segment operating income (loss)	$	24			$	495			$	1,181			$	336							2,036

General corporate expenses																					(122		)
Operating income																					$	1,914


Other financial information:
Depreciation and amortization	$	5			$	365			$	236			$	31			$	—			$	637

Total assets and investments by reporting segment [Table Text Block]	'
	The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:


		Total Assets at December 31,								Investments at December 31,								Additions to Long-Lived Assets at December 31,
		2013				2012				2013				2012				2013				2012			2011
		(Millions)
	Northeast G&P (1)	$	6,229			$	4,745			$	737			$	511			$	1,376			$	3,909		$	204

	Atlantic-Gulf	10,007				8,734				930				774				1,072				1,002			650

	West	4,767				4,688				—				—				210				360			301

	NGL & Petchem Services	3,035				2,469				520				515				746				571			314

	Other corporate assets	147				409				—				—				5				16			25

	Eliminations (2)	(614		)		(367		)		—				—				—				—			—

	Total	$	23,571			$	20,678			$	2,187			$	1,800			$	3,409			$	5,858		$	1,494





	-1	2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)


	-2	Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

General_and_Basis_of_Presentat1

General and Basis of Presentation (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

5 Months Ended

3 Months Ended

5 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 30, 2012

Mar. 31, 2013

Nov. 30, 2012

31-May-11

Jun. 30, 2012

31-May-11

Feb. 29, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 28, 2014

Dec. 31, 2013

Feb. 28, 2014

Dec. 31, 2013

Jun. 30, 2012

31-May-11

Dec. 31, 2013

GeismarAcquistion

Gulfstream Acquisition

Laser Acquisition [Member]

Canada Acquisition [Member]

Williams

Constitution Pipeline Company LLC

Geismar

Gulfstream Natural Gas System, L.L.C.

Laurel Mountain Midstream, LLC

Caiman Energy II, LLC

Discovery Producer Services LLC

Overland Pass Pipeline Company LLC

Common units

Subsequent Event [Member]

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Minimum period of construction for capitalization of interest

'3 months

Minimum total project cost for capitalization of interest

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

50.00%

51.00%

47.50%

60.00%

50.00%

Ownership percentage of an asset

50.00%

Business Acquisition [Line Items]

Variable Interest Entity Ownership Percentage

41.00%

Parent, limited partner ownership percentage

62.00%

Subsidiary, ownership percentage

83.30%

Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]

Business Acquisition, Percentage of Voting Interests Acquired

1.00%

83.30%

24.50%

1.00%

24.50%

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Business Combination, Consideration Transferred

Proceeds from Previous Acquisition

Partners' Capital Account, Units, Acquisitions

238,050

42,778,812

7,531,381

25,577,521

Parent, general partner ownership percentage

2.00%

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

42,778,812

238,050

632,584

Future Sales Of Class D Units

200

Payments to Acquire Businesses, Net of Cash Acquired

2,049

297

Reduction in the incentive distribution right payment

Combination Of Entities Under Common Control Effect On Net Income

Combination of Entities Under Common Control Effect on Other Comprehensive Income

-56

-16

Regulatory Assets [Line Items]

Regulatory Assets, Current

Regulatory Assets, Noncurrent

315

275

Total regulatory asset

354

314

Regulatory Liability, Current

Regulatory Liability, Noncurrent

289

250

Total regulatory liabilities

$308

$265

Acquisitions_Goodwill_and_Othe2

Acquisitions Goodwill and Other Intangible Assets (Details) (USD $)

12 Months Ended

2 Months Ended

4 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Feb. 17, 2012

Apr. 27, 2012

Dec. 31, 2012

Apr. 27, 2012

Customer Contracts [Member]

Customer Relationships [Member]

Other Intangible Assets [Member]

Laser Acquisition [Member]

Caiman Acquisition [Member]

Northeast G&P [Member]

Customer Contracts [Member]

Customer Relationships [Member]

Other Intangible Assets [Member]

Customer Contracts [Member]

Customer Relationships [Member]

Other Intangible Assets [Member]

Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]

Business Acquisition, Percentage of Voting Interests Acquired

1.00%

100.00%

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Business Acquisition, Cost of Acquired Entity, Cash Paid

$325

$1,720

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

7,531,381

11,779,296

Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable

441

603

Business Combination, Acquisition Related Costs

Business Acquisition, Purchase Price Allocation [Abstract]

Assets held-for-sale

Other current assets

Property, plant and equipment

158

656

Intangible assets

316

1,141

250

Current liabilities

-21

-94

Noncurrent liabilities

-3

Identifiable net assets acquired

476

1,968

Goodwill

646

649

290

356

Total

766

2,324

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Finite-Lived Intangible Assets, Gross

1,747

1,493

250

Finite-Lived Intangible Assets, Accumulated Amortization

-105

-45

-88

-38

-14

-6

-3

-1

Acquired Finite-lived Intangible Assets, Weighted Average Useful Life

'30 years

Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension

'9 years

'18 years

Amortization of Intangible Assets

Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]

Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months

Finite-Lived Intangible Assets, Amortization Expense, Year Two

Finite-Lived Intangible Assets, Amortization Expense, Year Three

Finite-Lived Intangible Assets, Amortization Expense, Year Four

Finite-Lived Intangible Assets, Amortization Expense, Year Five

$60

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Jan. 31, 2014

Dec. 31, 2013

Constitution Pipeline Company LLC [Member]

Variable Interest Entity, Primary Beneficiary [Member]

Variable Interest Entity, Not Primary Beneficiary [Member]

Cash and Cash Equivalents [Member]

Property Plant And Equipment [Member]

Accounts payable - trade [Member]

Other accrued liabilities [Member]

Other Current Liabilities [Member]

Regulatory liabilities, deferred income and other [Member]

Gulfstar One [Member]

Gunflint [Member]

Constitution Pipeline Company LLC [Member]

Laurel Mountain [Member]

Caiman Energy II LLC [Member]

Estimated Remaining Construction Costs For Variable Interest Entity [Member]

Equity Method Investments [Member]

Subsequent Event [Member]

Equity Method Investments [Member]

Variable Interest Entity [Line Items]

Variable Interest Entity Ownership Percentage

41.00%

51.00%

41.00%

51.00%

47.50%

Estimated remaining construction costs

$325

$134

$600

Contributions from noncontrolling interests

398

187

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

49.00%

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Variable Interest Entity, Consolidated, Carrying Amount, Assets

998

556

Variable Interest Entity, Consolidated, Carrying Amount, Liabilities

-120

-128

-3

-10

-115

-109

Variable Interest Entity, Nonconsolidated, Comparison of Carrying Amount of Assets and Liabilities to Maximum Loss Exposure [Abstract]

Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net

481

256

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount

$481

$380

$500

Allocation_of_Net_Income_and_D2

Allocation of Net Income and Distributions (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

21 Months Ended

In Millions, except Per Share data, 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, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 13, 2014

Subsequent Event [Member]

Allocation of net income to general partner:

Net income

$1,119

$1,291

$1,604

Net income applicable to pre-partnership operations allocated to general partner

-49

-244

-226

Net income applicable to noncontrolling interests

-3

Net costs charged directly to general partner

-2

Income subject to 2% allocation of general partner interest

1,068

1,048

1,376

General partner's share of net income

2.00%

General partner's allocated share of net income before items directly allocable to general partner interest

Priority allocations, including incentive distributions, paid to general partner

387

[1]

355

[1]

260

[1]

Net costs charged directly to general partner

-1

Pre-partnership net income allocated to general partner interest

244

226

Net income allocated to general partner

456

619

516

Net income

1,119

1,291

1,604

Net income allocated to general partner

456

619

516

Net income applicable to noncontrolling interests

Net income allocated to common limited partners

660

672

1,088

Distributions Made to Members or Limited Partners [Abstract]

Payment Date

12-Nov-13

9-Aug-13

10-May-13

8-Feb-13

9-Nov-12

10-Aug-12

11-May-12

10-Feb-12

11-Nov-11

12-Aug-11

13-May-11

11-Feb-11

13-Feb-14

[2]

Per Unit Distribution (Paid)

$0.88

$0.86

$0.85

$0.83

$0.81

$0.79

$0.78

$0.76

$0.75

$0.73

$0.72

$0.70

$0.89

[2]

Common Units Cash Distribution

385

357

351

329

287

274

268

227

217

213

208

204

392

[2]

2% General Partner Cash Distribution

[2]

Priority allocations, including incentive distributions, paid to general partner

121

112

104

153

[2]

Total Cash Distributions

442

489

473

442

394

373

362

311

294

286

276

268

1,846

1,440

1,124

556

[2]

Reduction in incentive distribution rights payment

$90

$147

[1]

The net income allocated to the general partnerbs capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period

[2]

On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014

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
Summary Of Related Party Transactions	'	'	'
Revenue	$0	$0	$310
Product costs	147	171	728
Accounts payable - trade	104	105	'
Proceeds	12	15	31
Contribution receivable	3	4	'
Employee costs [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Operating and maintenance expenses	339	275	241
Other [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Operating and maintenance expenses	0	0	305
Employee direct costs [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Selling, general, and administrative expenses	270	308	248
Employee allocated costs [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Selling, general, and administrative expenses	169	190	122
Reorganization-related allocated costs [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Selling, general, and administrative expenses	2	26	'
Equity method investees [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Accounts payable - trade	13	15	'
Service costs	67	75	57
Common management [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Revenue	131	61	62
Product costs	'	13	9
Reimbursable hurricane damage costs [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Maximum potential obligation	10	'	'
Reimbursable maintenance costs for certain government projects [Member]	'	'	'
Summary Of Related Party Transactions	'	'	'
Maximum potential obligation	$50	'	'

Investments_Details

Investments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Jun. 30, 2012	31-May-11
Investments	'		'		'	'	'
Investments	$2,187		$1,800		'	'	'
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	60		'		'	'	'
Percentage of Voting Interests Acquired	'		'		'	1.00%	'
Equity Method Investment, payments to purchase or contributions	439		471		197	'	'
Dividends and distributions	'		'		'	'	'
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	154		172		169	'	'
Summarized Financial Position of Equity Method Investments	'		'		'	'	'
Current assets	412		366		'	'	'
Noncurrent assets	5,956		5,225		'	'	'
Current liabilities	-264		-247		'	'	'
Noncurrent liabilities	-1,305		-1,301		'	'	'
Summarized Results of Operations of Equity Method Investments	'		'		'	'	'
Revenues	1,333		1,213		1,242	'	'
Operating income	367		378		535	'	'
Net income	291		309		460	'	'
Overland Pass Pipeline Company LLC [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Investments	452		454		'	'	'
Investment, Ownership Percentage	50.00%		'		'	'	'
Dividends and distributions	'		'		'	'	'
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	27		28		19	'	'
Gulfstream Natural Gas System, L.L.C.	'		'		'	'	'
Investments	'		'		'	'	'
Investments	333		348		'	'	'
Investment, Ownership Percentage	50.00%		'		'	'	'
Percentage of Voting Interests Acquired	'		'		'	1.00%	24.50%
Dividends and distributions	'		'		'	'	'
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	81		78		60	'	'
Discovery Producer Services LLC [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Investments	527	[1]	350	[1]	'	'	'
Investment, Ownership Percentage	60.00%		'		'	'	'
Equity Method Investment, payments to purchase or contributions	193		169		'	'	'
Dividends and distributions	'		'		'	'	'
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	12		21		40	'	'
Discovery Producer Services LLC [Member] \| Proportionate Share Of Amounts Remaining For Capital Projects [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Proportionate share of amounts remaining for capital projects	244		'		'	'	'
Laurel Mountain Midstream, LLC	'		'		'	'	'
Investments	'		'		'	'	'
Investments	481	[1]	444	[1]	'	'	'
Investment, Ownership Percentage	51.00%		'		'	'	'
Equity Method Investment, payments to purchase or contributions	42		174		137	'	'
Laurel Mountain Midstream, LLC \| Proportionate Share Of Amounts Remaining For Capital Projects [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Proportionate share of amounts remaining for capital projects	72		'		'	'	'
Caiman Energy II LLC [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Investments	256		67		'	'	'
Investment, Ownership Percentage	47.50%		'		'	'	'
Equity Method Investment, payments to purchase or contributions	192		69		'	'	'
Caiman Energy II LLC [Member] \| Proportionate Share Of Amounts Remaining For Capital Projects [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Proportionate share of amounts remaining for capital projects	119		'		'	'	'
Aux Sable Liquid Products LP [Member]	'		'		'	'	'
Dividends and distributions	'		'		'	'	'
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	20		28		35	'	'
Other [Member]	'		'		'	'	'
Investments	'		'		'	'	'
Investments	$138		$137		'	'	'

[1]	We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

Other_Income_and_Expense_Detai

Other Income and Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Northeast G&P [Member] \| Producer claim [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Settlement in principle of a pending producer claim	$25	$0	$0
Atlantic-Gulf [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Amortization of regulatory asset associated with asset retirement obligations	30	7	6
Project feasibility costs	4	21	10
Capitalization of project feasibility costs previously expensed	-1	-19	-11
Atlantic-Gulf [Member] \| Asset Impairment for Regulatory Action [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Write-off of the Eminence abandonment regulatory asset not recovered through rates	12	0	0
Insurance recoveries	-16	0	0
Charges related to leak at storage facility	3	2	15
NGL & Petchem Services [Member] \| Geismar Incident [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Insurance recoveries	-50	'	'
Net insurance recoveries associated with the Geismar Incident	-40	0	0
Insurance deductible expense	13	'	'
Insurable Expenses in Excess of our Deductibles	10	'	'
NGL & Petchem Services [Member] \| Geismar Incident [Member] \| Property Damage And Business Interruption Coverage [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Maximum insurance recoverable amount	500	'	'
NGL & Petchem Services [Member] \| Geismar Incident [Member] \| Property Damage [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Insurance deductibles	10	'	'
NGL & Petchem Services [Member] \| Geismar Incident [Member] \| Business Interruption [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Duration of waiting period before business interruption coverage begins	'60 days	'	'
NGL & Petchem Services [Member] \| Geismar Incident [Member] \| General Liability Coverage [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Maximum insurance recoverable amount	610	'	'
Insurance deductibles	2	'	'
NGL & Petchem Services [Member] \| Geismar Incident [Member] \| Workers Compensation Coverage [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Insurance deductibles	$1	'	'

Provision_Benefit_Table_Detail

Provision (Benefit) Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
State	$2	$11	$3
Foreign	-22	26	32
Total	-20	37	35
Deferred:	'	'	'
State	15	0	0
Foreign	35	5	11
Total	50	5	11
Provision (benefit) for income taxes	$30	$42	$46

Reconciliations_To_Recorded_Pr

Reconciliations To Recorded Provision for Income Taxes (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate Reconciliation, Amount [Abstract]	'	'	'
Provision (benefit) at statutory rate	$402	$467	$577
Increases (decreases) in taxes resulting from:	'	'	'
Income not subject to federal tax	-402	-467	-577
State income taxes	17	11	3
Foreign operations - net	13	31	43
Provision (benefit) for income taxes	$30	$42	$46

Provision_Benefit_for_Income_T2

Provision (Benefit) for Income Taxes Texuals (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Provision (Benefit) for Income Taxes (Textuals) [Abstract]	'	'	'	'
Deferred tax provision related to tax law change	$15	'	'	'
Income (Loss) from Continuing Operations before Income Taxes, Foreign	'	61	96	136
Deferred Tax Liabilities, Property, Plant and Equipment	'	117	72	'
Income Taxes Paid, Net	'	$2	$54	$35

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Pension Expense	$44	$41	$32
Defined Contribution Plan, Cost Recognized	16	19	17
Allocated Share-based Compensation Expense	12	13	11
Pension Benefits	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Benefit Obligation	1,400	1,500	'
Defined Benefit Plan, Funded Status of Plan	-143	-478	'
Other Postretirement Benefits	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Benefit Obligation	213	331	'
Defined Benefit Plan, Funded Status of Plan	-12	-156	'
Defined Benefit Plan, Net Periodic Benefit Cost	($4)	$4	($2)

Inventories_Details

Inventories (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Net [Abstract]	'	'
Natural gas liquids, olefins, and natural gas in underground storage	$111	$97
Other Inventory, Net of Reserves	83	78
Total Inventories	$194	$175

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details PPE) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	$25,062		$22,062	'
Accumulated depreciation	-7,437		-6,906	'
Property, plant, and equipment - net	17,625		15,156	'
Depreciation and amortization	729		690	634
Nonregulated [Member] \| Natural gas gathering and processing facilities [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	9,172		7,694	'
Nonregulated [Member] \| Natural gas gathering and processing facilities [Member] \| Minimum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, Plant and Equipment, Useful Life	'5 years	[1]	'	'
Nonregulated [Member] \| Natural gas gathering and processing facilities [Member] \| Maximum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, Plant and Equipment, Useful Life	'40 years	[1]	'	'
Nonregulated [Member] \| Construction in Progress [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	2,727		1,870	'
Nonregulated [Member] \| Other Capitalized Property Plant and Equipment [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	964		780	'
Nonregulated [Member] \| Other Capitalized Property Plant and Equipment [Member] \| Minimum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, Plant and Equipment, Useful Life	'3 years	[1]	'	'
Nonregulated [Member] \| Other Capitalized Property Plant and Equipment [Member] \| Maximum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, Plant and Equipment, Useful Life	'45 years	[1]	'	'
Regulated [Member] \| Natural gas transmission facilities [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	10,633		9,963	'
Regulated [Member] \| Natural gas transmission facilities [Member] \| Minimum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Regulated Property Plant And Equipment Depreciation Rate1	1.20%	[1]	'	'
Regulated [Member] \| Natural gas transmission facilities [Member] \| Maximum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Regulated Property Plant And Equipment Depreciation Rate1	6.97%	[1]	'	'
Regulated [Member] \| Construction in Progress [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	273		337	'
Regulated [Member] \| Other Capitalized Property Plant and Equipment [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment, at cost	1,293		1,418	'
Regulated [Member] \| Other Capitalized Property Plant and Equipment [Member] \| Minimum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Regulated Property Plant And Equipment Depreciation Rate1	1.35%	[1]	'	'
Regulated [Member] \| Other Capitalized Property Plant and Equipment [Member] \| Maximum [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Regulated Property Plant And Equipment Depreciation Rate1	33.33%	[1]	'	'
Regulated [Member] \| Excess Of Original Cost Of Regulated Facilities [Member]	'		'	'
Property, Plant and Equipment	'		'	'
Property, plant, and equipment - net	$785		$825	'
Period of straight-line amortization	'40 years		'	'

[1]	Estimated useful life and depreciation rates are presented as of DecemberB 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

Property_Plant_and_Equipment_D1

Property, Plant, and Equipment (Details ARO) (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	$579		$573
Liabilities incurred	8		8
Liabilities settled	-31	[1]	-44	[1]
Accretion expense	53		43
Revisions	-48	[2]	-1	[2]
Ending balance	561		579
Charges Related To Leak At Underground Natural Gas Storage Facility [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Liabilities settled	-25		-31
Revisions	9		13
Asset Retirement Obligation Costs [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Transco's annual funding commitment for ARO	$36		'

[1]	For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transcobs natural gas storage caverns that are associated with a leak in 2010.
[2]	Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transcobs natural gas storage caverns that were associated with a leak in 2010.

LongTerm_Debt_Details_1

Long-Term Debt (Details 1) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2012

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

3.35% Senior Unsecured Notes due 2022 [Member]

4.5% Senior Unsecured Notes due 2023 [Member]

5.8% Senior Unsecured Notes due 2043 [Member]

Transcontinental Gas Pipe Line Company, LLC [Member]

Northwest Pipeline LLC [Member]

Williams Partners L.P. [Member]

6.4% Senior Unsecured Notes due 2016 [Member]

6.05% Senior Unsecured Notes due 2018 [Member]

7.08% Debentures due 2026 [Member]

7.25% Debentures due 2026 [Member]

5.4% Senior Unsecured Notes due 2041 [Member]

4.45% Senior Unsecured Notes due 2042 [Member]

7% Senior Unsecured Notes due 2016 [Member]

5.95% Senior Unsecured Notes due 2017 [Member]

6.05% Senior Unsecured Notes due 2018 [Member]

7.125% Debentures due 2025 [Member]

3.8% Senior Unsecured Notes due 2015 [Member]

7.25% Senior Unsecured Notes due 2017 [Member]

5.25% Senior Unsecured Notes due 2020 [Member]

4.125% Senior Unsecured Notes due 2020 [Member]

4% Senior Unsecured Notes due 2021 [Member]

3.35% Senior Unsecured Notes due 2022 [Member]

4.5% Senior Unsecured Notes due 2023 [Member]

6.3% Senior Unsecured Notes due 2040 [Member]

5.8% Senior Unsecured Notes due 2043 [Member]

Debt Instrument [Line Items]

Long-term debt

$200

$250

$200

$375

$400

$175

$185

$250

$85

$750

$600

$1,500

$600

$500

$750

$600

$1,250

$400

Long-term debt interest rate

3.35%

4.50%

5.80%

6.40%

6.05%

7.08%

7.25%

5.40%

4.45%

7.00%

5.95%

6.05%

7.13%

3.80%

7.25%

5.25%

4.13%

4.00%

3.35%

4.50%

6.30%

5.80%

Credit facility loans

375

Unamortized debt discount

-21

-16

Long-term debt

$9,057

$8,437

LongTerm_Debt_Maturities_Detai

Long-Term Debt Maturities (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Long-term Debt, by Maturity [Abstract]	'
2014	$0
2015	750
2016	375
2017	785
2018	$500

LongTerm_Debt_Issuances_and_Re

Long-Term Debt Issuances and Retirements (Details 3) (USD $)	Aug. 31, 2012	Nov. 30, 2013	Nov. 30, 2013	Dec. 31, 2013	Jul. 31, 2012	Jul. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified	3.35% Senior Unsecured Notes due 2022 [Member]	4.5% Senior Unsecured Notes due 2023 [Member]	5.8% Senior Unsecured Notes due 2043 [Member]	Transcontinental Gas PipeLine Company, LLC [Member]	Transcontinental Gas PipeLine Company, LLC [Member]	Transcontinental Gas PipeLine Company, LLC [Member]	Williams Partners L. P. [Member]	Williams Partners L. P. [Member]	Williams Partners L. P. [Member]
				4.45% Senior Unsecured Notes due 2042 [Member]	4.45% Senior Unsecured Notes due 2042 [Member]	8.875% Senior Unsecured Notes due 2012 [Member]	3.35% Senior Unsecured Notes due 2022 [Member]	4.5% Senior Unsecured Notes due 2023 [Member]	5.8% Senior Unsecured Notes due 2043 [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Repayment of long-term debt	'	'	'	'	'	$325	'	'	'
Long-term debt face amount	$750	$600	$400	'	$400	'	'	'	'
Long-term debt interest rate	3.35%	4.50%	5.80%	4.45%	4.45%	8.88%	3.35%	4.50%	5.80%

Credit_Facility_and_Commercial

Credit Facility and Commercial Paper (Details 4) (USD $)	12 Months Ended									12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Jul. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
			Northwest Pipeline LLC [Member]	Transcontinental Gas PipeLine Company, LLC [Member]	$2.4 Billion Unsecured Credit Facility terminated July 2013 [Member]	$2.5 Billion Unsecured Credit Facility [Member]	$2.5 Billion Unsecured Credit Facility [Member]	$2.5 Billion Unsecured Credit Facility [Member]	$2.5 Billion Unsecured Credit Facility Letter of Credit [Member]	Commercial Paper [Member]
							Northwest Pipeline LLC [Member]	Transcontinental Gas PipeLine Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]	'	'	'	'	'	'	'	'	'	'
Credit facility, capacity	'	'	'	'	$2,400	$2,500	$500	$500	$1,300	$2,000
Credit facility, loans outstanding	0	375	'	'	'	0	'	'	'	'
Credit facility, letters of credit outstanding	'	'	'	'	'	'	'	'	0	'
Commercial paper, outstanding	225	0	'	'	'	'	'	'	'	225
Commercial paper, weighted average interest rate	'	'	'	'	'	'	'	'	'	0.42%
Commercial paper, maximum maturity	'	'	'	'	'	'	'	'	'	'397 days
Additional amount by which credit facility can be increased	'	'	'	'	'	500	'	'	'	'
Maximum ratio of debt to EBITDA	500.00%	'	'	'	'	'	'	'	'	'
Minimum aggregate purchase price of acquisitions impacting maximum ratio of debt to EBITDA	$50	'	'	'	'	'	'	'	'	'
Maximum ratio of debt to EBITDA after acquisition	550.00%	'	'	'	'	'	'	'	'	'
Maximum ratio of debt to capitalization	'	'	65.00%	65.00%	'	'	'	'	'	'
Commitment fee	0.18%	'	'	'	'	'	'	'	'	'

Cash_Payments_For_Interest_Net

Cash Payments For Interest (Net of Amounts Capitalized) (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]	'	'	'
Cash payments for interest (net of amounts capitalized)	$366	$381	$387

LeasesLessee_Details_6

Leases-Lessee (Details 6) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Future minimum annual rentals under noncancelable operating leases	'	'	'
2014	$42	'	'
2015	36	'	'
2016	35	'	'
2017	31	'	'
2018	29	'	'
Thereafter	123	'	'
Total	296	'	'
Operating Leased Assets [Line Items]	'	'	'
Total rent expense	51	46	38
Jicarilla Apache Nation [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Future minimum annual rental payment of a certain significant lease	$8	'	'

Partners_Capital_Details_Textu

Partners' Capital (Details Textuals) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

Aug. 31, 2013

Mar. 31, 2013

Aug. 31, 2012

Jun. 30, 2012

Apr. 30, 2012

Feb. 29, 2012

Jan. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Aug. 31, 2013

Mar. 31, 2013

Aug. 31, 2012

Apr. 30, 2012

Feb. 29, 2012

Nov. 30, 2012

Feb. 29, 2012

Apr. 30, 2012

Option on Securities [Member]

Geismar Acquisition [Member]

Laser Acquisition [Member]

CaimanAcquisition [Member]

Business Acquisition [Line Items]

Partners' Capital Account, Units, Sold in Public Offering

21,500,000

8,500,000

10,000,000

7,000,000

3,225,000

1,687,500

1,275,000

973,368

1,050,000

Partners' Capital Account, Private Placement of Units

$1,000,000,000

Partners' Capital Account, Units, Acquisitions

238,050

42,778,812

7,531,381

11,779,296

Partners' Capital Account, Units, Sold in Private Placement

3,000,000

16,360,133

Percentage of units held by the public

36.00%

30.00%

Percentage of outstanding units voting as a single class to remove general partner

66.67%

Days after the end of each quarter to receive cash distributions

'45 days

Business Acquisition, Percentage of Voting Interests Acquired

1.00%

83.30%

Net Proceeds from Issuance of Common Limited Partners Units

$1,200,000,000

$760,000,000

$488,000,000

$581,000,000

$64,000,000

$426,000,000

$1,962,000,000

$2,559,000,000

Partners' Capital Account, Units, Sale of Units

14,250,000

Partners_Capital_Incentive_Dis

Partners' Capital Incentive Distributions Quarterly Target Amount (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Minimum Quarterly Distribution Per Unit [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Unitholders	98.00%
General Partner	2.00%
Quarterly Distribution Target Amount	$0.35
First Target Distribution [Member] \| Maximum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Unitholders	98.00%
General Partner	2.00%
Quarterly Distribution Target Amount	$0.40
Second Target Distribution [Member] \| Minimum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Unitholders	85.00%
General Partner	15.00%
Quarterly Distribution Target Amount	$0.40
Second Target Distribution [Member] \| Maximum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Quarterly Distribution Target Amount	$0.44
Third Target Distribution [Member] \| Minimum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Unitholders	75.00%
General Partner	25.00%
Quarterly Distribution Target Amount	$0.44
Third Target Distribution [Member] \| Maximum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Quarterly Distribution Target Amount	$0.53
Thereafter [Member] \| Minimum [Member]	'
Incentive Distribution Target Amount Per Unit [Line Items]	'
Unitholders	50.00%
General Partner	50.00%
Quarterly Distribution Target Amount	$0.53

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Additional disclosures:	'	'	'
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	0	0	'
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	0	0	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Receivables by product or service	568	589	'
Customer Concentration Risk [Member] \| Sales Revenue, Net [Member]	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Consolidated revenue, major customer, percentage	9.00%	14.00%	17.00%
Customer accounted for ten percent of consolidated revenues	1	1	1
NGLs, natural gas, and related products and services [member]	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Receivables by product or service	341	406	'
Transportation of natural gas and related products [member]	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Receivables by product or service	193	169	'
Other Receivable [Member]	'	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'	'
Receivables by product or service	34	14	'
Carrying Amount [Member]	'	'	'
Additional disclosures:	'	'	'
Notes receivable and other	7	11	'
Long-term debt	-9,057	-8,437	'
Fair Value [Member]	'	'	'
Additional disclosures:	'	'	'
Notes receivable and other	7	10	'
Long-term debt	-9,581	-9,624	'
Level 1 [Member]	'	'	'
Additional disclosures:	'	'	'
Notes receivable and other	1	2	'
Long-term debt	0	0	'
Level 2 [Member]	'	'	'
Additional disclosures:	'	'	'
Notes receivable and other	6	8	'
Long-term debt	-9,581	-9,624	'
Level 3 [Member]	'	'	'
Additional disclosures:	'	'	'
Notes receivable and other	0	0	'
Long-term debt	0	0	'
Fair Value, Measurements, Recurring [Member] \| Carrying Amount [Member]	'	'	'
Measured on a recurring basis:	'	'	'
ARO Trust investments	33	18	'
Fair Value, Measurements, Recurring [Member] \| Carrying Amount [Member] \| Not Designated as Hedging Instrument [Member]	'	'	'
Measured on a recurring basis:	'	'	'
Energy derivative assets	3	5	'
Energy derivative liabilities	-3	-1	'
Fair Value, Measurements, Recurring [Member] \| Fair Value [Member]	'	'	'
Measured on a recurring basis:	'	'	'
ARO Trust investments	33	18	'
Fair Value, Measurements, Recurring [Member] \| Fair Value [Member] \| Not Designated as Hedging Instrument [Member]	'	'	'
Measured on a recurring basis:	'	'	'
Energy derivative assets	3	5	'
Energy derivative liabilities	-3	-1	'
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]	'	'	'
Measured on a recurring basis:	'	'	'
ARO Trust investments	33	18	'
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Not Designated as Hedging Instrument [Member]	'	'	'
Measured on a recurring basis:	'	'	'
Energy derivative assets	0	0	'
Energy derivative liabilities	0	0	'
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]	'	'	'
Measured on a recurring basis:	'	'	'
ARO Trust investments	0	0	'
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Not Designated as Hedging Instrument [Member]	'	'	'
Measured on a recurring basis:	'	'	'
Energy derivative assets	0	0	'
Energy derivative liabilities	-1	0	'
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]	'	'	'
Measured on a recurring basis:	'	'	'
ARO Trust investments	0	0	'
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Not Designated as Hedging Instrument [Member]	'	'	'
Measured on a recurring basis:	'	'	'
Energy derivative assets	3	5	'
Energy derivative liabilities	-2	-1	'

Contingent_Liabilities_Details

Contingent Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 11, 2013
Contingent Liabilities [Line Items]	'	'
Accrued environmental loss liabilities	$20,000,000	'
Commitments For Construction And Acquisition Of Property Plant And Equipment	1,400,000,000	'
Customer Refund Liability, Current	98,000,000	'
Notice of Penalty	'	99,000
Environmental Protection Agency [Member]	'	'
Contingent Liabilities [Line Items]	'	'
Accrued environmental loss liabilities	13,000,000	'
Natural gas underground storage facilities [Member]	'	'
Contingent Liabilities [Line Items]	'	'
Accrued environmental loss liabilities	$7,000,000	'

Segment_Disclosures_Details

Segment Disclosures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Revenues	$6,835	$7,471	$7,916
Long-lived assets	19,913	17,507	12,449
UNITED STATES	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Revenues	6,685	7,320	7,714
Long-lived assets	18,776	16,637	11,866
CANADA	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Revenues	150	151	202
Long-lived assets	$1,137	$870	$583

Segment_Disclosures_Details_1

Segment Disclosures (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	$6,835		$7,471		$7,916
Segment profit (loss)	1,677		1,907		2,174
Equity earnings (losses)	104		111		142
Income (loss) from investments	-3		-4		-4
Operating income	1,407		1,610		1,914
Other financial information:	'		'		'
Depreciation and amortization	791		734		637
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	23,571		20,678		'
Investments	2,187		1,800		'
Additions to long-lived assets	3,409		5,858		1,494
Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	2,914		2,714		2,518
Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	3,921		4,757		5,398
Northeast G&P [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	335		168		49
Northeast G&P [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	166		2		0
Atlantic-Gulf [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	1,414		1,371		1,332
Atlantic-Gulf [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	830		709		606
West [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	1,053		1,067		1,053
West [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	64		40		11
NGL & Petchem Services [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	112		108		84
NGL & Petchem Services [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	2,861		4,006		4,781
Operating Segments [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Operating income	1,576		1,800		2,036
Operating Segments [Member] \| Northeast G&P [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	501		170		49
Segment profit (loss)	-24		-37		23
Equity earnings (losses)	-7		-23		-1
Income (loss) from investments	0		0		0
Operating income	-17		-14		24
Other financial information:	'		'		'
Depreciation and amortization	132		76		5
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	6,229		4,745		'
Investments	737		511		'
Additions to long-lived assets	1,376		3,909	[1]	204
Operating Segments [Member] \| Northeast G&P [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	335		168		49
Operating Segments [Member] \| Northeast G&P [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	166		2		0
Operating Segments [Member] \| Atlantic-Gulf [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	2,349		2,455		2,469
Segment profit (loss)	614		574		585
Equity earnings (losses)	72		92		90
Income (loss) from investments	0		0		0
Operating income	542		482		495
Other financial information:	'		'		'
Depreciation and amortization	363		381		365
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	10,007		8,734		'
Investments	930		774		'
Additions to long-lived assets	1,072		1,002		650
Operating Segments [Member] \| Atlantic-Gulf [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	1,424		1,383		1,332
Operating Segments [Member] \| Atlantic-Gulf [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	925		1,072		1,137
Operating Segments [Member] \| West [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	1,826		2,201		2,690
Segment profit (loss)	741		980		1,181
Equity earnings (losses)	0		0		0
Income (loss) from investments	0		0		0
Operating income	741		980		1,181
Other financial information:	'		'		'
Depreciation and amortization	236		234		236
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	4,767		4,688		'
Investments	0		0		'
Additions to long-lived assets	210		360		301
Operating Segments [Member] \| West [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	1,054		1,072		1,057
Operating Segments [Member] \| West [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	772		1,129		1,633
Operating Segments [Member] \| NGL & Petchem Services [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	3,267		4,372		4,921
Segment profit (loss)	346		390		385
Equity earnings (losses)	39		42		53
Income (loss) from investments	-3		-4		-4
Operating income	310		352		336
Other financial information:	'		'		'
Depreciation and amortization	60		43		31
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	3,035		2,469		'
Investments	520		515		'
Additions to long-lived assets	746		571		314
Operating Segments [Member] \| NGL & Petchem Services [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	112		108		84
Operating Segments [Member] \| NGL & Petchem Services [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	3,155		4,264		4,837
Intersegment Eliminations [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-1,108		-1,727		-2,213
Other financial information:	'		'		'
Depreciation and amortization	0		0		0
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	-614	[2]	-367	[2]	'
Investments	0		0		'
Additions to long-lived assets	0		0		0
Intersegment Eliminations [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-11		-17		-4
Intersegment Eliminations [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-1,097		-1,710		-2,209
Intersegment Eliminations [Member] \| Northeast G&P [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	0		0		0
Intersegment Eliminations [Member] \| Northeast G&P [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	0		0		0
Intersegment Eliminations [Member] \| Atlantic-Gulf [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-10		-12		0
Intersegment Eliminations [Member] \| Atlantic-Gulf [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-95		-363		-531
Intersegment Eliminations [Member] \| West [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-1		-5		-4
Intersegment Eliminations [Member] \| West [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-708		-1,089		-1,622
Intersegment Eliminations [Member] \| NGL & Petchem Services [Member] \| Service [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	0		0		0
Intersegment Eliminations [Member] \| NGL & Petchem Services [Member] \| Product [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Revenues	-294		-258		-56
Corporate Non-Segment [Member]	'		'		'
Reconciliation of segment revenues and segment profit (loss)	'		'		'
Operating income	-169		-190		-122
Total assets, investments and additions to long-lived assets by reporting segment	'		'		'
Total assets	147		409		'
Investments	0		0		'
Additions to long-lived assets	$5		$16		$25

[1]	2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 b Acquisitions, Goodwill, and Other Intangible Assets.)
[2]	Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	19-May-14	Mar. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified			Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]
				A5.4SeniorUnsecuredNotesDue2044 [Member]	A4.3SeniorUnsecuredNotesDue2024 [Member]
Subsequent Event [Line Items]	'	'	'	'	'
Debt Instrument, Face Amount	'	'	'	$500	$1,000
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	5.40%	4.30%
Commercial paper	$225	$0	$370	'	'