DCP Midstream (DCP-PC) 10-Q 7 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	1-May-15
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	DPM
Entity Registrant Name	DCP MIDSTREAM PARTNERS, LP
Entity Central Index Key	1338065
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		114,738,148

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$33	$25
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1 million	73	106
Affiliates	130	164
Inventories	36	63
Unrealized gains on derivative instruments	196	230
Other	2	2
Total current assets	470	590
Property, plant and equipment, net	3,374	3,347
Goodwill	154	154
Intangible assets, net	117	120
Investments in unconsolidated affiliates	1,481	1,459
Unrealized gains on derivative instruments	20	39
Other long-term assets	28	30
Total assets	5,644	5,739
Accounts payable:
Trade	136	196
Affiliates	26	27
Long-term Debt, Current Maturities	250	250
Unrealized losses on derivative instruments	33	43
Interest Payable, Current	33	21
Other	47	64
Total current liabilities	525	601
Long-term debt	2,062	2,061
Other long-term liabilities	51	51
Total liabilities	2,638	2,713
Commitments and contingent liabilities
Equity:
Limited partners (114,738,148 and 113,949,868 common units issued and outstanding, respectively)	2,964	2,984
General partner	18	18
Accumulated other comprehensive loss	-8	-9
Total partners' equity	2,974	2,993
Noncontrolling interests	32	33
Total equity	3,006	3,026
Total liabilities and equity	$5,644	$5,739

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Allowance for doubtful accounts	$1	$1
Common unitholders, units issued	114,738,148	113,949,868
Common unitholders, units outstanding	114,738,148	113,949,868

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$470	$1,013
Transportation, processing and other	79	83
Gain (Loss) on Derivative Instruments, Net, Pretax	19	-15
Total operating revenues	568	1,081
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	402	885
Operating and maintenance expense	47	45
Depreciation and amortization expense	29	26
General and administrative expense	21	16
Other expense (income)	0	1
Total operating costs and expenses	499	973
Operating Income (Loss)	69	108
Interest expense	-22	-19
Earnings from unconsolidated affiliates	23	3
Income before income taxes	70	92
Income tax expense	-1	-3
Net income	69	89
Net income attributable to noncontrolling interests	0	-10
Net income attributable to partners	69	79
Net income attributable to predecessor operations	0	-6
General partner's interest in net income	-31	-26
Net income allocable to limited partners	38	47
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$0.33	$0.50
Weighted Average Limited Partnership Units Outstanding, Basic	114.2	93.4
Weighted Average Limited Partnership Units Outstanding, Diluted	114.2	93.4
Third Party [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	189	371
Transportation, processing and other	56	51
Gain (Loss) on Derivative Instruments, Net, Pretax	5	-3
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	367	785
General and administrative expense	3	5
Affiliated Entity [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	281	642
Transportation, processing and other	23	32
Gain (Loss) on Derivative Instruments, Net, Pretax	14	-12
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	35	100
General and administrative expense	$18	$11

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$69	$89
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	1	2
Total other comprehensive income	1	2
Total comprehensive income	70	91
Total comprehensive income attributable to noncontrolling interests	0	-10
Total comprehensive income attributable to partners	$70	$81

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
OPERATING ACTIVITIES:
Net income	$69	$89
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	29	26
Earnings from unconsolidated affiliates	-23	-3
Distributions from unconsolidated affiliates	26	13
Net unrealized losses on derivative instruments	43	14
Other, net	2	4
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable	61	-14
Inventories	27	34
Accounts payable	-59	-16
Accrued interest	12	6
Other current assets and liabilities	-3	-7
Other long-term assets and liabilities	4	0
Net cash provided by operating activities	188	146
INVESTING ACTIVITIES:
Capital expenditures	-65	-63
Acquisitions, net of cash acquired	0	-100
Payments to Acquire Equity Method Investments	0	669
Investments in unconsolidated affiliates	-25	-65
Proceeds from sales of assets	0	1	[1]
Net cash used in investing activities	-90	-896
FINANCING ACTIVITIES:
Proceeds from long-term debt	162	719
Payments of long-term debt	-162	0
Payments of commercial paper, net	0	-314
Payments of deferred financing costs	0	-6
Excess purchase price over acquired interests and commodity hedges	0	-14
Proceeds from issuance of common units, net of offering costs	31	677
Net change in advances to predecessor from DCP Midstream, LLC	0	-6
Distributions to limited partners and general partner	-120	-86
Distributions to noncontrolling interests	-1	-10
Purchase of additional interest in a subsidiary	0	-198
Contributions from noncontrolling interests	0	3
Net cash (used in) provided by financing activities	-90	765
Net change in cash and cash equivalents	8	15
Cash and cash equivalents, beginning of period	25	12
Cash and cash equivalents, end of period	$33	$27
[1]	(a)The financial information for the three months ended MarchB 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)	Total	Predecessor Equity [Member]	Limited Partners [Member]	General Partner [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Noncontrolling Interests [Member]
In Millions
Beginning balance at Dec. 31, 2013	$2,213	$40	$1,948	$8	($11)	$228
Net income	89	6	47	26		10
Other comprehensive (loss) income	2	0			2
Partners Capital Net Change In Parent Advances To Predecessor	-6	-6
Partners' Capital Account, Acquisitions	-40	-40	0	0	0	0
Partners Capital Account Acquisitions Issuance Of Units	225		225
Excess purchase price over carrying value of acquired net assets	-158		-158
Issuance of common units	677	0	677	0	0	0
Distributions to limited partners and general partner	-86	0	-65	-21	0	0
Distributions to noncontrolling interests	-10	0	0	0	0	-10
Contributions from noncontrolling interests	3	0	0	0	0	3
Acquisition of additional interest in subsidiary	-198	0	0	0	0	-198
Ending balance at Mar. 31, 2014	2,711	0	2,674	13	-9	33
Beginning balance at Dec. 31, 2014	3,026		2,984	18	-9	33
Net income	69		38	31		0
Other comprehensive (loss) income	1				1
Issuance of common units	31		31
Distributions to limited partners and general partner	-120		-89	-31
Distributions to noncontrolling interests	-1					-1
Contributions from noncontrolling interests	0
Ending balance at Mar. 31, 2015	$3,006		$2,964	$18	($8)	$32

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Equity (Parenthetical)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Consideration financed through issuance of common units		4,497,158
Issuance of common units		14,375,000
Limited Partners [Member]
Issuance of common units	788,033	14,375,000

Description_of_Business_and_Ba

Description of Business and Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation
	DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we, our or the Partnership, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate; and transporting, storing and selling propane in wholesale markets.
	We are a Delaware limited partnership that was formed in August 2005. Our partnership includes our Natural Gas Services, NGL Logistics and Wholesale Propane Logistics segments. For additional information regarding these segments, see Note 14 - Business Segments.
	Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC’s employees provide administrative support to us and operate most of our assets. DCP Midstream, LLC owns approximately 21.4% of us, including limited partner and general partner interests.
	The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.
	Our predecessor results consist of the Lucerne 1 plant, which we acquired from DCP Midstream, LLC on March 28, 2014. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior periods were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our condensed consolidated financial statements include the historical results of our Lucerne 1 plant for all periods presented.
	The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. All intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been included in the condensed consolidated financial statements as transactions between affiliates.
	The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. Results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2014 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.

New_Accounting_Pronouncements_

New Accounting Pronouncements (Notes)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements
	Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2015-06 “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions,” or ASU 2015-06 - In April 2015, the FASB issued ASU 2015-06, which specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners, which is typically the earnings per unit measure presented in the financial statements, would not change as a result of the dropdown transaction. This ASU is effective for annual and interim reporting periods beginning after December 15, 2015 and is required to be applied retrospectively. The adoption of this ASU will have no impact on our condensed consolidated results of operations as we have not historically changed previously reported earnings per limited partner unit as a result of dropdown transactions.
	FASB ASU 2015-03 “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost,” or ASU 2015-03 - In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This ASU is effective for annual reporting periods beginning after December 15, 2015, after which we will present debt issuance costs as a direct reduction from debt on our condensed consolidated balance sheets for all periods presented. The adoption of this ASU will have no impact on our condensed consolidated results of operations and cash flows.
	FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU is effective for annual reporting periods beginning after December 15, 2015 and we are currently assessing the impact of adoption of this ASU on our condensed consolidated results of operations, cash flows and financial position.
	FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification, or ASC, Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2016. In April 2015, the FASB proposed to defer the effective date of the ASU to December 15, 2017, with the option to adopt as early as December 15, 2016. The FASB has not yet voted on the proposal. We are currently assessing the impact of adoption of this ASU on our condensed consolidated results of operations, cash flows and financial position.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions
	On January 1, 2015, we entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, we paid $1 million for our interest in the joint venture. The anticipated total consideration of approximately $26 million includes our proportionate share in construction costs for an anticipated expansion of the existing Panola NGL pipeline. The Panola NGL pipeline originates in Carthage, Texas and extends approximately 180 miles to Mont Belvieu, Texas. The expansion will extend the Panola NGL pipeline approximately 60 miles and increase capacity from approximately 50 MBbls/d to 100 MBbls/d. We, WGR Asset Holding Company LLC, which is an affiliate of Anadarko Petroleum Corporation, and MarkWest Panola Pipeline L.L.C. will each own a 15% interest in Panola. Enterprise will own a 55% interest in Panola and will construct the expansion and operate the pipeline. In accordance with the joint venture agreement, we will not participate in the earnings of the Panola pipeline until the expansion is complete, which is expected to be in service in the first quarter of 2016.

Agreements_and_Transactions_wi

Agreements and Transactions with Affiliates	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Agreements and Transactions with Affiliates	Agreements and Transactions with Affiliates
	DCP Midstream, LLC
	Services Agreement and Other General and Administrative Charges
	We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. In the event we acquire assets or our business otherwise expands, the annual fee under the Services Agreement is subject to adjustment based on the nature and extent of general and administrative services performed by DCP Midstream, LLC, as well as an annual adjustment based on changes to the Consumer Price Index.
	On February 23, 2015, the annual fee payable under the Services Agreement was increased by approximately $25 million to $71 million, following approval of the increase by the special committee of the board of directors of the General Partner. Our growth, both from organic growth and acquisitions, has resulted in the Partnership becoming a much larger portion of the business of DCP Midstream, LLC. Additionally, our expansion into downstream logistics has required DCP Midstream, LLC to expand its capabilities and provide us with a broader range of services than what was previously provided. As a result, DCP Midstream, LLC initiated a comprehensive review of its costs and the methodology for allocating general and administrative services. The result of this review reflects the level and cost of general and administrative services provided to us by DCP Midstream, LLC as the operator of our assets. The annual fee was effective starting January 1, 2015.
	The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC:
		Three Months Ended March 31,
		2015		2014
		(Millions)
	Services Agreement	$	18	$	7
	Other fees — DCP Midstream, LLC	—		4
	Total — DCP Midstream, LLC	$	18	$	11
	In addition to the fees paid pursuant to the Services Agreement, we incurred allocated expenses, including executive compensation, insurance and internal audit fees with DCP Midstream, LLC of less than $1 million for each of the three months ended March 31, 2015 and 2014. The Eagle Ford system incurred $4 million in general and administrative expenses directly from DCP Midstream, LLC for the three months ended March 31, 2014, before the reallocation of the Eagle Ford system to the Services Agreement on March 31, 2014.
	Other Agreements and Transactions with DCP Midstream, LLC
	As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.
	In conjunction with our acquisition of the O'Connor and Lucerne 1 plants, we entered into long-term fee-based processing agreements with DCP Midstream, LLC pursuant to which DCP Midstream, LLC agreed to pay us (i) a fixed demand charge on a portion of the plants' capacities, and (ii) a throughput fee on all volumes processed for DCP Midstream, LLC at the plants. We report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates. Under the O'Connor agreement, we received fees of $9 million and $7 million during the three months ended March 31, 2015 and 2014. Under the Lucerne 1 agreement, we received fees of $3 million during the three months ended March 31, 2015.
	Spectra Energy
	Commodity Transactions - We purchase natural gas and other NGL products from and provide gathering, transportation and other services to Spectra Energy. Management anticipates continuing to purchase and sell commodities and provide services to Spectra Energy in the ordinary course of business.
	Summary of Transactions with Affiliates
	The following table summarizes our transactions with affiliates:
		Three Months Ended March 31,
		2015		2014
		(Millions)
	DCP Midstream, LLC:
	Sales of natural gas, propane, NGLs and condensate	$	281	$	642
	Transportation, processing and other	$	23	$	18
	Purchases of natural gas, propane and NGLs	$	25	$	80
	Gains from commodity derivative activity, net	$	14	$	(12	)
	General and administrative expense	$	18	$	11
	Spectra Energy:
	Purchases of natural gas, propane and NGLs	$	10	$	20
	Transportation, processing and other	$	—	$	14
	We had balances with affiliates as follows:
		March 31,		December 31,
		2015		2014
		(Millions)
	DCP Midstream, LLC:
	Accounts receivable	$	130	$	163
	Accounts payable	$	21	$	24
	Unrealized gains on derivative instruments — current	$	32	$	207
	Unrealized gains on derivative instruments — long-term	$	7	$	25
	Unrealized losses on derivative instruments — current	$	33	$	43
	Spectra Energy:
	Accounts receivable	$	—	$	1
	Accounts payable	$	5	$	3

Inventories

Inventories	3 Months Ended
	Mar. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Inventories
	Inventories were as follows:
		March 31,		December 31,
		2015		2014
		(Millions)
	Natural gas	$	21	$	36
	NGLs	15		27
	Total inventories	$	36	$	63
	We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the condensed consolidated statements of operations. We recognized $4 million and $3 million in lower of cost or market adjustments during the three months ended March 31, 2015 and 2014, respectively.

Property_Plant_and_Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment
	A summary of property, plant and equipment by classification is as follows:
		Depreciable	March 31,			December 31,
		Life	2015			2014
			(Millions)
	Gathering and transmission systems	20 — 50 Years	$	2,267		$	2,209
	Processing, storage, and terminal facilities	35 — 60 Years	2,042			2,071
	Other	3 —  30 Years	55			50
	Construction work in progress		300			281
	Property, plant and equipment		4,664			4,611
	Accumulated depreciation		(1,290		)	(1,264		)
	Property, plant and equipment, net		$	3,374		$	3,347
	Interest capitalized on construction projects for the three months ended March 31, 2015 and 2014 was $3 million and $1 million, respectively.
	Depreciation expense was $26 million and $24 million for the three months ended March 31, 2015 and 2014, respectively.

Investments_in_Unconsolidated_

Investments in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates
	The following table summarizes our investments in unconsolidated affiliates:
				Carrying Value as of
		Percentage		March 31,				December 31,
		Ownership		2015				2014
				(Millions)
	DCP Sand Hills Pipeline, LLC	33.33%		$	427			$	413
	Discovery Producer Services LLC	40%		413				406
	DCP Southern Hills Pipeline, LLC	33.33%		327				329
	Front Range Pipeline LLC	33.33%		171				169
	Texas Express Pipeline LLC	10%		98				98
	Mont Belvieu Enterprise Fractionator	12.50%		24				23
	Mont Belvieu 1 Fractionator	20%		13				14
	Other	Various		8				7
	Total investments in unconsolidated affiliates			$	1,481			$	1,459
	Earnings (losses) from investments in unconsolidated affiliates were as follows:
		Three Months Ended March 31,
		2015				2014
		(Millions)
	DCP Sand Hills Pipeline, LLC	$	11			$	—
	Mont Belvieu Enterprise Fractionator	4				4
	Front Range Pipeline LLC	4				(1		)
	DCP Southern Hills Pipeline, LLC	3				—
	Texas Express Pipeline LLC	2				—
	Mont Belvieu 1 Fractionator	1				1
	Discovery Producer Services LLC	(2		)		(1		)
	Total earnings from unconsolidated affiliates	$	23			$	3
	The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
		Three Months Ended March 31,
		2015				2014
		(Millions)
	Statements of operations (a):
	Operating revenue	$	233			$	111
	Operating expenses	$	129			$	82
	Net income	$	103			$	29
		March 31,				December 31,
		2015				2014
		(Millions)
	Balance sheets (a):
	Current assets	$	200			$	207
	Long-term assets	5,270				5,157
	Current liabilities	(195		)		(200		)
	Long-term liabilities	(239		)		(164		)
	Net assets	$	5,036			$	5,000
	(a) In accordance with the Panola joint venture agreement, earnings do not accrue to our interest until the expansion of the pipeline is complete. Accordingly, we will not include activity related to Panola in the above tables until the period in which the expansion is complete and earnings accrue to our interest.

Fair_Value_Measurement

Fair Value Measurement	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement
	Determination of Fair Value
	Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.
	•	Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.
	•	Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.
	•	Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.
	We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.
	The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 10 - Risk Management and Hedging Activities.
	Valuation Hierarchy
	Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.
	•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
	•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
	•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.
	A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
	Commodity Derivative Assets and Liabilities
	We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.
	Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
	Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.
	Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.
	Interest Rate Derivative Assets and Liabilities
	We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
	Nonfinancial Assets and Liabilities
	We utilize fair value to perform impairment tests as required on our property, plant and equipment; goodwill; and long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.
	The following table presents the financial instruments carried at fair value as of March 31, 2015 and December 31, 2014, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:
		31-Mar-15												31-Dec-14
		Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
											Carrying										Carrying
											Value										Value
		(Millions)
	Current assets:
	Commodity derivatives (a)	$	—		$	78		$	118		$	196		$	—	$	92		$	138	$	230
	Short-term investments (b)	$	33		$	—		$	—		$	33		$	24	$	—		$	—	$	24
	Long-term assets (c):
	Commodity derivatives	$	—		$	20		$	—		$	20		$	—	$	21		$	18	$	39
	Current liabilities (d):
	Commodity derivatives	$	—		$	(33	)	$	—		$	(33	)	$	—	$	(43	)	$	—	$	(43	)
	(a)	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.
	(b)	Includes short-term money market securities included in cash and cash equivalents in our condensed consolidated balance sheets.
	(c)	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.
	(d)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.
	Changes in Levels 1 and 2 Fair Value Measurements
	The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the three months ended March 31, 2015 and 2014, there were no transfers into or out of Level 1 and Level 2 of the fair value hierarchy.
	Changes in Level 3 Fair Value Measurements
	The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.
	We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.
		Commodity Derivative Instruments
		Current			Long-			Current			Long-
		Assets			Term			Liabilities			Term
					Assets						Liabilities
		(Millions)
	Three months ended March 31, 2015 (a):
	Beginning balance	$	138		$	18		$	—		$	—
	Net unrealized gains (losses) included in earnings (b)	20			(18		)	—			—
	Settlements	(40		)	—			—			—
	Ending balance	$	118		$	—		$	—		$	—
	Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	20		$	(18	)	$	—		$	—
	Three months ended March 31, 2014 (a):
	Beginning balance	$	65		$	75		$	—		$	—
	Net unrealized gains (losses) included in earnings (b)	17			(15		)	(1		)	—
	Settlements	(12		)	—			—			—
	Ending balance	$	70		$	60		$	(1	)	$	—
	Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	19		$	(15	)	$	(1	)	$	—
	(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 2015 and 2014.
	(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.
Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs
We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.
	31-Mar-15
Product Group	Fair Value			Forward
				Curve Range
	(Millions)
Assets
NGLs	$	118		$0.17-$1.12		Per gallon
Estimated Fair Value of Financial Instruments
Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.
We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.
We determine the fair value of our fixed-rate Senior Notes based on quotes obtained from bond dealers. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of March 31, 2015 and December 31, 2014, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, were as follows:
		31-Mar-15						31-Dec-14
		Carrying Value			Fair Value			Carrying Value			Fair Value
	(Millions)
Senior Notes		$	2,312		$	2,157		$	2,311		$	2,334

Debt

Debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt
		March 31,			December 31,
		2015			2014
		(Millions)
	Debt Securities
	Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015	250			250
	Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
	Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019	325			325
	Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
	Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			500
	Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044	400			400
	Unamortized discount	(13		)	(14		)
	Total debt	2,312			2,311
	Current maturities of long-term debt	(250		)	(250		)
	Total long-term debt	$	2,062		$	2,061
	Amended and Restated Credit Agreement
	On May 1, 2014, we entered into a $1.25 billion amended and restated senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement will be used for working capital requirements and other general partnership purposes including acquisitions.
	Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. In the first quarter of 2015, our credit rating was lowered below investment grade. As a result of this ratings action, interest rates under the Amended and Restated Credit Agreement increased to: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.45% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.30% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.
	As of March 31, 2015, we had unused capacity of $1,249 million, net of letters of credit, under the Amended and Restated Credit Agreement, of which $1,205 million was available for general working capital purposes. Our borrowing capacity may be limited by financial covenant requirements set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.
	The Amended and Restated Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.
	Commercial Paper Program
	Prior to March 2015, we had a commercial paper program, or the Commercial Paper Program, under which we issued unsecured commercial paper notes. During the first quarter of 2015, our credit rating was lowered below investment grade. As a result of this ratings action, we no longer have the Commercial Paper Program. Our available liquidity under the Commercial Paper Program was replaced with the Amended and Restated Credit Agreement.
	Debt Securities
	In March 2014, we issued $325 million of 2.70% five-year Senior Notes due April 1, 2019 and $400 million of 5.60% 30-year Senior Notes due April 1, 2044. We received proceeds of $320 million and $392 million, respectively, net of underwriters’ fees, related expenses and unamortized discounts which we used to pay a portion of the consideration for the contribution and acquisition of: (i) a 33.33% interest in each of the Sand Hills and Southern Hills pipeline entities; (ii) the remaining 20% interest in the Eagle Ford system; (iii) the Lucerne 1 plant; and (iv) the Lucerne 2 plant, or the March 2014 Transactions. Interest on the notes is paid semi-annually on April 1 and October 1 of each year, commencing October 1, 2014. The notes will mature on April 1, 2019 and April 1, 2044, respectively, unless redeemed prior to maturity.
	The notes are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness, including indebtedness under our Amended and Restated Credit Agreement. We are not required to make mandatory redemption or sinking fund payments with respect to any of these notes, and they are redeemable at a premium at our option. The underwriters’ fees and related expenses are deferred in other long-term assets in our condensed consolidated balance sheets and will be amortized over the term of the notes.
	The future maturities of long-term debt in the year indicated are as follows:
		Debt
		Maturities
		(Millions)
	2016	$	—
	2017	500
	2018	—
	2019	325
	2020	—
	Thereafter	1,250
		2,075
	Unamortized discount	(13		)
	Total	$	2,062

Risk_Management_and_Hedging_Ac

Risk Management and Hedging Activities	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management and Hedging Activities	Risk Management and Hedging Activities
	Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.
	Commodity Price Risk
	Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2017 with commodity derivative instruments, with the majority of our positions settling through the first quarter of 2016. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL hedges from 2015 through 2016 are direct product hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.
	Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our condensed consolidated statements of operations as a gain or loss on commodity derivative activity.
	Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.
	As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.
	Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
	A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.
	Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of March 31, 2015.
	Interest Rate Risk
	We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.
	Prior to June 30, 2014, we had interest rate swap agreements with notional values totaling $150 million, which were accounted for under the mark-to-market method of accounting and repriced prospectively approximately every 30 days. Under the terms of the interest rate swap agreements, we paid fixed-rates ranging from 2.94% to 2.99%, and received interest payments based on the one-month LIBOR. These interest rate swap agreements settled in June 2014. Prior to August of 2013, these interest rate swaps were designated as cash flow hedges whereby the effective portions of changes in fair value were recognized in AOCI in the condensed consolidated balance sheets. In March 2014, we paid down a portion of the balance outstanding under our Commercial Paper Program and reclassified the remaining loss of $1 million in AOCI into earnings as interest expense.
	In conjunction with the issuance of our 4.95% Senior Notes in March 2012, we entered into forward-starting interest rate swap agreements to reduce our exposure to market rate fluctuations prior to issuance. These derivative financial instruments were designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixed the rate we would pay on a portion of our 4.95% Senior Notes, the deferred loss in AOCI will be amortized into interest expense through the maturity of the notes in 2022. The balance in AOCI of these cash flow hedges was in a loss position of $3 million as of March 31, 2015.
	Contingent Credit Features
	Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.
	We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.
	•	If we were to have an effective event of default under our Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.
	•	Certain of our ISDA counterparties would have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.
	•	Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Amended and Restated Credit Agreement. As of March 31, 2015, we were not a party to any agreements that would trigger the cross-default provisions.
	Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.
	Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of March 31, 2015, all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of March 31, 2015, we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contracts that contain credit-risk related contingent features were in a net asset position.
	Offsetting
	Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the condensed consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments:
		31-Mar-15												31-Dec-14
		Gross Amounts				Amounts Not				Net				Gross Amounts				Amounts Not			Net
		of Assets and				Offset in the				Amount				of Assets and				Offset in the			Amount
		(Liabilities)				Balance Sheet -								(Liabilities)				Balance Sheet -
		Presented in the				Financial								Presented in the				Financial
		Balance Sheet				Instruments (a)								Balance Sheet				Instruments (a)
		(Millions)
	Assets:
	Commodity derivatives	$	216			$	(32	)		$	184			$	269			$	(42	)	$	227
	Liabilities:
	Commodity derivatives	$	(33	)		$	32			$	(1	)		$	(43	)		$	42		$	(1	)
	(a)	There is no cash collateral pledged or received against these positions.
	Summarized Derivative Information
	The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2015 and December 31, 2014.
	Balance Sheet Line Item	March 31,				December 31,				Balance Sheet Line Item		March 31,				December 31,
		2015				2014						2015				2014
		(Millions)										(Millions)
	Derivative Assets Not Designated as Hedging Instruments:									Derivative Liabilities Not Designated as Hedging Instruments:
	Commodity derivatives:									Commodity derivatives:
	Unrealized gains on derivative instruments — current	$	196			$	230			Unrealized losses on derivative instruments — current		$	(33	)		$	(43	)
	Unrealized gains on derivative instruments — long-term	20				39				Unrealized losses on derivative instruments — long-term		—				—
		$	216			$	269					$	(33	)		$	(43	)
	The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2015:
		Interest						Commodity				Foreign				Total
		Rate Cash						Cash Flow				Currency
		Flow						Hedges				Cash Flow
		Hedges										Hedges (a)
		(Millions)
	Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)				$	(6	)		$	1			$	(9	)
	Losses reclassified from AOCI to earnings — effective portion	1				(b)		—				—				1
	Net deferred (losses) gains in AOCI (ending balance)	$	(3	)				$	(6	)		$	1			$	(8	)
	Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)				$	—			$	—			$	(1	)
	(a)	Relates to Discovery, our unconsolidated affiliate.
	(b)	Included in interest expense in our condensed consolidated statements of operations.
	For the three months ended March 31, 2015, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2015, no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
	The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2014:
		Interest						Commodity				Foreign				Total
		Rate Cash						Cash Flow				Currency
		Flow						Hedges				Cash Flow
		Hedges										Hedges (a)
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(6	)				$	(6	)		$	1			$	(11	)
Losses reclassified from AOCI to earnings — effective portion	$	2			(b)		$	—			$	—			$	2
Net deferred (losses) gains in AOCI (ending balance)	$	(4	)				$	(6	)		$	1			$	(9	)
(a)	Relates to Discovery, our unconsolidated affiliate.
(b)	Included in interest expense in our condensed consolidated statements of operations.
For the three months ended March 31, 2014, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2014, $1 million of derivative losses were reclassified from AOCI to interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the condensed consolidated statements of operations. The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected:
Commodity Derivatives: Statements of Operations Line Item	Three Months Ended March 31,
	2015				2014
	(Millions)
Third party:
Realized gains (losses)	$	7			$	(3	)
Unrealized losses	(2		)		—
Gains (losses) from commodity derivative activity, net	$	5			$	(3	)
Affiliates:
Realized gains	$	54			$	1
Unrealized losses	(40		)		(13		)
Gains (losses) from commodity derivative activity, net —affiliates	$	14			$	(12	)
Interest Rate Derivatives: Statements of Operations Line Item	Three Months Ended March 31,
	2015				2014
	(Millions)
Third party:
Realized losses	$	—			$	(1	)
Unrealized gains	—				1
Interest expense	$	—			$	—
We do not have any derivative financial instruments that qualify as a hedge of a net investment.
The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below.
	31-Mar-15
	Crude Oil			Natural Gas			Natural Gas			Natural Gas
							Liquids			Basis Swaps
Year of Expiration	Net (Short)			Net			Net			Net Long Position
	Position			(Short)			(Short)			(MMBtu)
	(Bbls)			Position			Position
				(MMBtu)			(Bbls)
2015	(561,825	)		(12,429,125	)		(4,231,200	)		2,675,000
2016	(561,922	)		(5,668,564	)		(813,267	)		1,690,000
2017	—			(6,387,500	)		—			—
	31-Mar-14
	Crude Oil			Natural Gas			Natural Gas			Natural Gas
							Liquids			Basis Swaps
Year of Expiration	Net (Short)			Net (Short)			Net (Short)			Net Long
	Position			Position			Position			Position
	(Bbls)			(MMBtu)			(Bbls)			(MMBtu)
2014	(520,575	)		(4,014,200	)		(4,602,350	)		4,305,000
2015	(745,695	)		(13,458,975	)		(5,691,570	)		2,185,000
2016	(561,922	)		(3,668,564	)		(813,267	)		—
2017	—			(6,387,500	)		—			—

Partnership_Equity_and_Distrib

Partnership Equity and Distributions	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Partnership Equity and Distributions	Partnership Equity and Distributions
	During the three months ended March 31, 2015, we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and accrued offering costs of less than $1 million, which were used to finance growth opportunities and for general partnership purposes. As of March 31, 2015, approximately $349 million remained available for sale pursuant to our 2014 equity distribution agreement.
	In March 2014, we issued 14,375,000 common units to the public at $48.90 per unit. We received proceeds of $677 million, net of offering costs.
	In March 2014, we issued 4,497,158 common units to DCP Midstream, LLC as partial consideration for the March 2014 Transactions.
	The following table presents our cash distributions paid in 2015 and 2014:
	Payment Date	Per Unit		Total Cash
		Distribution		Distribution
				(Millions)
	February 13, 2015	$	0.78	$	120
	November 14, 2014	$	0.77	$	117
	August 14, 2014	$	0.7575	$	111
	May 15, 2014	$	0.745	$	106
	February 14, 2014	$	0.7325	$	86

Net_Income_or_Loss_per_Limited

Net Income or Loss per Limited Partner Unit	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Net Income or Loss per Limited Partner Unit	Net Income or Loss per Limited Partner Unit
	Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under our Long-Term Incentive Plan. The dilutive effect of unit-based awards was 11,573, and 9,742 equivalent units during the three months ended March 31, 2015 and 2014, respectively.

Commitments_and_Contingent_Lia

Commitments and Contingent Liabilities	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities
	Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flow.
	Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations and safety standards. In addition, there is increasing focus, from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our condensed consolidated results of operations, financial position or cash flows.

Business_Segments

Business Segments	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Business Segments	Business Segments
	Our operations are located in the United States and are organized into three reporting segments: Natural Gas Services; NGL Logistics; and Wholesale Propane Logistics. Our chief operating decision maker regularly reviews financial information about our operating segments, which are aggregated into the reporting units presented, in deciding how to allocate resources and evaluate performance.
	Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing, treating, processing, transporting and storing natural gas, and fractionating NGLs. The segment consists of our Eagle Ford system, East Texas system, Southeast Texas system, Michigan system, Northern Louisiana system, Southern Oklahoma system, Wyoming system, DJ Basin system, 75% interest in the Piceance system and 40% interest in Discovery.
	NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of our storage facility in Michigan, the DJ Basin fractionators, 12.5% interest in the Mont Belvieu Enterprise fractionator, 20% interest in the Mont Belvieu 1 fractionator, 10% interest in the Texas Express intrastate pipeline, 15% interest in the Panola intrastate pipeline, 33.33% interests in the Southern Hills, Sand Hills and Front Range pipelines, the Black Lake and Wattenberg interstate pipelines and the Seabreeze and Wilbreeze intrastate pipelines.
	Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of propane and other liquefied petroleum gases by pipeline, rail or ship to our terminals that store and deliver the product to distributors. The segment consists of 6 rail terminals, one marine terminal, one pipeline terminal and access to several open-access pipeline terminals.
	These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the operations of each segment.
	The following tables set forth our segment information:
	Three Months Ended March 31, 2015:
		Natural Gas			NGL			Wholesale			Other			Total
		Services			Logistics			Propane
								Logistics
		(Millions)
	Total operating revenue	$	440		$	18		$	110		$	—		$	568
	Gross margin (a)	$	119		$	18		$	29		$	—		$	166
	Operating and maintenance expense	(40		)	(4		)	(3		)	—			(47		)
	Depreciation and amortization expense	(26		)	(2		)	(1		)	—			(29		)
	General and administrative expense	—			—			—			(21		)	(21		)
	Earnings from unconsolidated affiliates	(2		)	25			—			—			23
	Interest expense	—			—			—			(22		)	(22		)
	Income tax expense	—			—			—			(1		)	(1		)
	Net income (loss)	$	51		$	37		$	25		$	(44	)	$	69
	Net income attributable to noncontrolling interests	—			—			—			—			—
	Net income (loss) attributable to partners	$	51		$	37		$	25		$	(44	)	$	69
	Non-cash derivative mark-to-market (b)	$	(45	)	$	—		$	3		$	(1	)	$	(43	)
	Non-cash lower of cost or market adjustments	$	3		$	—		$	1		$	—		$	4
	Capital expenditures	$	50		$	13		$	2		$	—		$	65
	Investments in unconsolidated affiliates	$	12		$	13		$	—		$	—		$	25
	Three Months Ended March 31, 2014:
		Natural Gas			NGL			Wholesale			Other			Total
		Services (c)			Logistics			Propane
								Logistics
		(Millions)
	Total operating revenue	$	849		$	17		$	215		$	—		$	1,081
	Gross margin (a)	$	164		$	17		$	15		$	—		$	196
	Operating and maintenance expense	(38		)	(4		)	(3		)	—			(45		)
	Depreciation and amortization expense	(24		)	(1		)	(1		)	—			(26		)
	General and administrative expense	—			—			—			(16		)	(16		)
	Other expense	(1		)	—			—			—			(1		)
	Earnings from unconsolidated affiliates	(1		)	4			—			—			3
	Interest expense	—			—			—			(19		)	(19		)
	Income tax expense	—			—			—			(3		)	(3		)
	Net income (loss)	$	100		$	16		$	11		$	(38	)	$	89
	Net income attributable to noncontrolling interests	(10		)	—			—			—			(10		)
	Net income (loss) attributable to partners	$	90		$	16		$	11		$	(38	)	$	79
	Non-cash derivative mark-to-market (b)	$	(12	)	$	—		$	(1	)	$	(1	)	$	(14	)
	Non-cash lower of cost or market adjustments	$	—		$	—		$	3		$	—		$	3
	Capital expenditures	$	55		$	4		$	4		$	—		$	63
	Acquisition expenditures	$	100		$	669		$	—		$	—		$	769
	Investments in unconsolidated affiliates	$	42		$	23		$	—		$	—		$	65
		March 31,			December 31,
		2015			2014
		(Millions)
	Segment long-term assets:
	Natural Gas Services	$	4,364		$	3,609
	NGL Logistics	651			1,364
	Wholesale Propane Logistics	121			118
	Other (d)	38			58
	Total long-term assets	5,174			5,149
	Current assets	470			590
	Total assets	$	5,644		$	5,739
	(a)	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
	(b)	Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.
	(c)	The segment information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information, similar to the pooling method.
	(d)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	3 Months Ended
	Mar. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information
		Three Months Ended March 31,
		2015		2014
		(Millions)
	Cash paid for interest:
	Cash paid for interest, net of amounts capitalized	$	8	$	10
	Non-cash investing and financing activities:
	Property, plant and equipment acquired with accounts payable	$	32	$	12
	Other non-cash changes in property, plant and equipment	$	—	$	—
	Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions	$	—	$	81
	Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$	—	$	144

Supplementary_Information_Cond

Supplementary Information - Condensed Consolidating Financial Information	3 Months Ended
	Mar. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Supplementary Information - Condensed Consolidating Financial Information	Supplementary Information — Condensed Consolidating Financial Information
	The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream Partners, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.
		Condensed Consolidating Balance Sheet
		31-Mar-15
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	—			$	32			$	1		$	—		$	33
	Accounts receivable, net	—				—				203			—			203
	Inventories	—				—				36			—			36
	Other	—				—				198			—			198
	Total current assets	—				32				438			—			470
	Property, plant and equipment, net	—				—				3,374			—			3,374
	Goodwill and intangible assets, net	—				—				271			—			271
	Advances receivable — consolidated subsidiaries	2,521				1,946				—			(4,467		)	—
	Investments in consolidated subsidiaries	453				803				—			(1,256		)	—
	Investments in unconsolidated affiliates	—				—				1,481			—			1,481
	Other long-term assets	—				17				31			—			48
	Total assets	$	2,974			$	2,798			$	5,595		$	(5,723	)	$	5,644
	LIABILITIES AND EQUITY
	Accounts payable and other current liabilities	$	—			$	283			$	242		$	—		$	525
	Advances payable — consolidated subsidiaries	—				—				4,467			(4,467		)	—
	Long-term debt	—				2,062				—			—			2,062
	Other long-term liabilities	—				—				51			—			51
	Total liabilities	—				2,345				4,760			(4,467		)	2,638
	Commitments and contingent liabilities
	Equity:
	Partners’ equity:
	Net equity	2,974				456				808			(1,256		)	2,982
	Accumulated other comprehensive loss	—				(3		)		(5		)	—			(8		)
	Total partners’ equity	2,974				453				803			(1,256		)	2,974
	Noncontrolling interests	—				—				32			—			32
	Total equity	2,974				453				835			(1,256		)	3,006
	Total liabilities and equity	$	2,974			$	2,798			$	5,595		$	(5,723	)	$	5,644
		Condensed Consolidating Balance Sheet
		December 31, 2014
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	—			$	24			$	1		$	—		$	25
	Accounts receivable, net	—				—				270			—			270
	Inventories	—				—				63			—			63
	Other	—				—				232			—			232
	Total current assets	—				24				566			—			590
	Property, plant and equipment, net	—				—				3,347			—			3,347
	Goodwill and intangible assets, net	—				—				274			—			274
	Advances receivable — consolidated subsidiaries	2,610				1,962				—			(4,572		)	—
	Investments in consolidated subsidiaries	383				712				—			(1,095		)	—
	Investments in unconsolidated affiliates	—				—				1,459			—			1,459
	Other long-term assets	—				17				52			—			69
	Total assets	$	2,993			$	2,715			$	5,698		$	(5,667	)	$	5,739
	LIABILITIES AND EQUITY
	Accounts payable and other current liabilities	$	—			$	271			$	330		$	—		$	601
	Advances payable — consolidated subsidiaries	—				—				4,572			(4,572		)	—
	Long-term debt	—				2,061				—			—			2,061
	Other long-term liabilities	—				—				51			—			51
	Total liabilities	—				2,332				4,953			(4,572		)	2,713
	Commitments and contingent liabilities
	Equity:
	Partners’ equity:
Net equity	2,993				387				717			(1,095		)	3,002
Accumulated other comprehensive loss	—				(4		)		(5		)	—			(9		)
Total partners’ equity	2,993				383				712			(1,095		)	2,993
Noncontrolling interests	—				—				33			—			33
Total equity	2,993				383				745			(1,095		)	3,026
Total liabilities and equity	$	2,993			$	2,715			$	5,698		$	(5,667	)	$	5,739
	Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2015
	Parent				Subsidiary				Non-			Consolidating			Consolidated
	Guarantor				Issuer				Guarantor			Adjustments
									Subsidiaries
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—			$	—			$	470		$	—		$	470
Transportation, processing and other	—				—				79			—			79
Gains from commodity derivative activity, net	—				—				19			—			19
Total operating revenues	—				—				568			—			568
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—				—				402			—			402
Operating and maintenance expense	—				—				47			—			47
Depreciation and amortization expense	—				—				29			—			29
General and administrative expense	—				—				21			—			21
Total operating costs and expenses	—				—				499			—			499
Operating income	—				—				69			—			69
Interest expense, net	—				(22		)		—			—			(22		)
Income from consolidated subsidiaries	69				91				—			(160		)	—
Earnings from unconsolidated affiliates	—				—				23			—			23
Income before income taxes	69				69				92			(160		)	70
Income tax expense	—				—				(1		)	—			(1		)
Net income	69				69				91			(160		)	69
Net income attributable to noncontrolling interests	—				—				—			—			—
Net income attributable to partners	$	69			$	69			$	91		$	(160	)	$	69
	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended March 31, 2015
	Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
	Guarantor				Issuer				Subsidiaries			Adjustments
	(Millions)
Net income	$	69			$	69			$	91		$	(160	)	$	69
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—				1				—			—			1
Other comprehensive income from consolidated subsidiaries	1				—				—			(1		)	—
Total other comprehensive income	1				1				—			(1		)	1
Total comprehensive income	70				70				91			(161		)	70
Total comprehensive income attributable to noncontrolling interests	—				—				—			—			—
Total comprehensive income attributable to partners	$	70			$	70			$	91		$	(161	)	$	70
	Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2014 (a)
	Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
	Guarantor				Issuer				Subsidiaries			Adjustments
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—			$	—			$	1,013		$	—		$	1,013
Transportation, processing and other	—				—				83			—			83
Gains from commodity derivative activity, net	—				—				(15		)	—			(15		)
Total operating revenues	—				—				1,081			—			1,081
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—				—				885			—			885
Operating and maintenance expense	—				—				45			—			45
Depreciation and amortization expense	—				—				26			—			26
General and administrative expense	—				—				16			—			16
Other expense	—				—				1			—			1
Total operating costs and expenses	—				—				973			—			973
Operating income	—				—				108			—			108
Interest expense	—				(19		)		—			—			(19		)
Earnings from unconsolidated affiliates	—				—				3			—			3
Income from consolidated subsidiaries	79				98				—			(177		)	—
Income before income taxes	79				79				111			(177		)	92
Income tax expense	—				—				(3		)	—			(3		)
Net income	79				79				108			(177		)	89
Net income attributable to noncontrolling interests	—				—				(10		)	—			(10		)
Net income attributable to partners	$	79			$	79			$	98		$	(177	)	$	79
(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.
	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended March 31, 2014 (a)
	Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
	Guarantor				Issuer				Subsidiaries			Adjustments
	(Millions)
Net income	$	79			$	79			$	108		$	(177	)	$	89
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—				2				—			—			2
Other comprehensive income from consolidated subsidiaries	2				—				—			(2		)	—
Total other comprehensive income	2				2				—			(2		)	2
Total comprehensive income	81				81				108			(179		)	91
Total comprehensive income attributable to noncontrolling interests	—				—				(10		)	—			(10		)
Total comprehensive income attributable to partners	$	81			$	81			$	98		$	(179	)	$	81
(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.
	Condensed Consolidating Statement of Cash Flows
	Three Months Ended March 31, 2015
	Parent			Subsidiary			Non-Guarantor			Consolidating		Consolidated
	Guarantor			Issuer			Subsidiaries			Adjustments
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	—			(8	)		196			—		188
INVESTING ACTIVITIES:
Intercompany transfers	89			16			—			(105	)	—
Capital expenditures	—			—			(65	)		—		(65	)
Investments in unconsolidated affiliates	—			—			(25	)		—		(25	)
Net cash used in investing activities	89			16			(90	)		(105	)	(90	)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(105	)		105		—
Proceeds from long-term debt	—			162			—			—		162
Payments of long-term debt	—			(162	)		—			—		(162	)
Proceeds from issuance of common units, net of offering costs	31			—			—			—		31
Distributions to limited partners and general partner	(120	)		—			—			—		(120	)
Distributions to noncontrolling interests	—			—			(1	)		—		(1	)
Net cash used in financing activities	(89	)		—			(106	)		105		(90	)
Net change in cash and cash equivalents	—			8			—			—		8
Cash and cash equivalents, beginning of period	—			24			1			—		25
Cash and cash equivalents, end of period	—			32			1			—		33
	Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2014 (a)
	Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
	Guarantor				Issuer				Subsidiaries			Adjustments
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—			$	(11	)		$	157		$	—		$	146
INVESTING ACTIVITIES:
Intercompany transfers	(591		)		(365		)		—			956			—
Capital expenditures	—				—				(63		)	—			(63		)
Acquisitions, net of cash acquired	—				—				(100		)	—			(100		)
Acquisition of unconsolidated affiliates	—				—				(669		)	—			(669		)
Investments in unconsolidated affiliates	—				—				(65		)	—			(65		)
Proceeds from sale of assets	—				—				1			—			1
Net cash used in investing activities	(591		)		(365		)		(896		)	956			(896		)
FINANCING ACTIVITIES:
Intercompany transfers	—				—				956			(956		)	—
Proceeds from long-term debt	—				719				—			—			719
Payments of long-term debt	—				(314		)		—			—			(314		)
Payment of deferred financing costs	—				(6		)		—			—			(6		)
Proceeds from issuance of common units, net of offering costs	677				—				—			—			677
Excess purchase price over acquired interests and commodity hedges	—				—				(14		)	—			(14		)
Net change in advances to predecessor from DCP Midstream, LLC	—				—				(6		)	—			(6		)
Distributions to limited partners and general partner	(86		)		—				—			—			(86		)
Distributions to noncontrolling interests	—				—				(10		)	—			(10		)
Purchase of additional interest in a subsidiary	—				—				(198		)	—			(198		)
Contributions from noncontrolling interests	—				—				3			—			3
Net cash provided by financing activities	591				399				731			(956		)	765
Net change in cash and cash equivalents	—				23				(8		)	—			15
Cash and cash equivalents, beginning of period	—				—				12			—			12
Cash and cash equivalents, end of period	$	—			$	23			$	4		$	—		$	27
(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	On April 28, 2015, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution will be paid on May 15, 2015 to unitholders of record on May 8, 2015.
	In April 2015, we filed a new universal shelf registration statement with the SEC, that became effective upon filing, in order to replace an existing shelf registration statement that was set to expire. As with the expiring shelf registration statement, the new universal shelf registration statement also allows us to issue an unlimited amount of common units and debt securities. We have issued no common units or debt securities under this registration statement.

Description_of_Business_and_Ba1

Description of Business and Basis of Presentation Description of Business and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control.
Business Combinations and Other Purchase of Business Transactions, Policy [Policy Text Block]	Our predecessor results consist of the Lucerne 1 plant, which we acquired from DCP Midstream, LLC on March 28, 2014. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior periods were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our condensed consolidated financial statements include the historical results of our Lucerne 1 plant for all periods presented.
Equity Method Investments, Policy [Policy Text Block]	Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

Fair_Value_Measurement_Fair_Va

Fair Value Measurement Fair Value Measurement (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Fair Value Measurement, Policy [Policy Text Block]	Determination of Fair Value
	Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.
	•	Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.
	•	Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.
	•	Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.
	We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.
	The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 10 - Risk Management and Hedging Activities.
	Valuation Hierarchy
	Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.
	•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
	•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
	•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.
	A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
	Commodity Derivative Assets and Liabilities
	We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.
	Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
	Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.
	Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.
	Interest Rate Derivative Assets and Liabilities
	We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
	Nonfinancial Assets and Liabilities
	We utilize fair value to perform impairment tests as required on our property, plant and equipment; goodwill; and long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

Risk_Management_and_Hedging_Ac1

Risk Management and Hedging Activities Derivatives, Methods of Accounting (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Derivatives, Policy [Policy Text Block]	Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2017 with commodity derivative instruments, with the majority of our positions settling through the first quarter of 2016. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL hedges from 2015 through 2016 are direct product hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.
	Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our condensed consolidated statements of operations as a gain or loss on commodity derivative activity.
	Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.
	As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.
	Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
	A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.
	Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of March 31, 2015.
	Interest Rate Risk
	We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

Agreements_and_Transactions_wi1

Agreements and Transactions with Affiliates (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Schedule of Fees Incurred and Other Fees Paid	The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC:
		Three Months Ended March 31,
		2015		2014
		(Millions)
	Services Agreement	$	18	$	7
	Other fees — DCP Midstream, LLC	—		4
	Total — DCP Midstream, LLC	$	18	$	11
Summary of Transactions with Affiliates	The following table summarizes our transactions with affiliates:
		Three Months Ended March 31,
		2015		2014
		(Millions)
	DCP Midstream, LLC:
	Sales of natural gas, propane, NGLs and condensate	$	281	$	642
	Transportation, processing and other	$	23	$	18
	Purchases of natural gas, propane and NGLs	$	25	$	80
	Gains from commodity derivative activity, net	$	14	$	(12	)
	General and administrative expense	$	18	$	11
	Spectra Energy:
	Purchases of natural gas, propane and NGLs	$	10	$	20
	Transportation, processing and other	$	—	$	14
	We had balances with affiliates as follows:
		March 31,		December 31,
		2015		2014
		(Millions)
	DCP Midstream, LLC:
	Accounts receivable	$	130	$	163
	Accounts payable	$	21	$	24
	Unrealized gains on derivative instruments — current	$	32	$	207
	Unrealized gains on derivative instruments — long-term	$	7	$	25
	Unrealized losses on derivative instruments — current	$	33	$	43
	Spectra Energy:
	Accounts receivable	$	—	$	1
	Accounts payable	$	5	$	3

Inventories_Tables

Inventories (Tables)	3 Months Ended
	Mar. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories were as follows:
		March 31,		December 31,
		2015		2014
		(Millions)
	Natural gas	$	21	$	36
	NGLs	15		27
	Total inventories	$	36	$	63

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2015
Property, Plant and Equipment [Abstract]
Classification of Property, Plant and Equipment	A summary of property, plant and equipment by classification is as follows:
		Depreciable	March 31,			December 31,
		Life	2015			2014
			(Millions)
	Gathering and transmission systems	20 — 50 Years	$	2,267		$	2,209
	Processing, storage, and terminal facilities	35 — 60 Years	2,042			2,071
	Other	3 —  30 Years	55			50
	Construction work in progress		300			281
	Property, plant and equipment		4,664			4,611
	Accumulated depreciation		(1,290		)	(1,264		)
	Property, plant and equipment, net		$	3,374		$	3,347

Investments_in_Unconsolidated_1

Investments in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	The following table summarizes our investments in unconsolidated affiliates:
				Carrying Value as of
		Percentage		March 31,				December 31,
		Ownership		2015				2014
				(Millions)
	DCP Sand Hills Pipeline, LLC	33.33%		$	427			$	413
	Discovery Producer Services LLC	40%		413				406
	DCP Southern Hills Pipeline, LLC	33.33%		327				329
	Front Range Pipeline LLC	33.33%		171				169
	Texas Express Pipeline LLC	10%		98				98
	Mont Belvieu Enterprise Fractionator	12.50%		24				23
	Mont Belvieu 1 Fractionator	20%		13				14
	Other	Various		8				7
	Total investments in unconsolidated affiliates			$	1,481			$	1,459
Earnings from Investments in Unconsolidated Affiliates	Earnings (losses) from investments in unconsolidated affiliates were as follows:
		Three Months Ended March 31,
		2015				2014
		(Millions)
	DCP Sand Hills Pipeline, LLC	$	11			$	—
	Mont Belvieu Enterprise Fractionator	4				4
	Front Range Pipeline LLC	4				(1		)
	DCP Southern Hills Pipeline, LLC	3				—
	Texas Express Pipeline LLC	2				—
	Mont Belvieu 1 Fractionator	1				1
	Discovery Producer Services LLC	(2		)		(1		)
	Total earnings from unconsolidated affiliates	$	23			$	3
Equity Method Investment Summarized Financial Information, Statement of Operations	The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
		Three Months Ended March 31,
		2015				2014
		(Millions)
	Statements of operations (a):
	Operating revenue	$	233			$	111
	Operating expenses	$	129			$	82
	Net income	$	103			$	29
Equity Method Investment Summarized Financial Information, Balance Sheet
		March 31,				December 31,
		2015				2014
		(Millions)
	Balance sheets (a):
	Current assets	$	200			$	207
	Long-term assets	5,270				5,157
	Current liabilities	(195		)		(200		)
	Long-term liabilities	(239		)		(164		)
	Net assets	$	5,036			$	5,000
	(a) In accordance with the Panola joint venture agreement, earnings do not accrue to our interest until the expansion of the pipeline is complete. Accordingly, we will not include activity related to Panola in the above tables until the period in which the expansion is complete and earnings accrue to our interest.

Fair_Value_Measurement_Tables

Fair Value Measurement (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Financial Instruments Carried at Fair Value	The following table presents the financial instruments carried at fair value as of March 31, 2015 and December 31, 2014, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:
		31-Mar-15												31-Dec-14
		Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
											Carrying										Carrying
											Value										Value
		(Millions)
	Current assets:
	Commodity derivatives (a)	$	—		$	78		$	118		$	196		$	—	$	92		$	138	$	230
	Short-term investments (b)	$	33		$	—		$	—		$	33		$	24	$	—		$	—	$	24
	Long-term assets (c):
	Commodity derivatives	$	—		$	20		$	—		$	20		$	—	$	21		$	18	$	39
	Current liabilities (d):
	Commodity derivatives	$	—		$	(33	)	$	—		$	(33	)	$	—	$	(43	)	$	—	$	(43	)
	(a)	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.
	(b)	Includes short-term money market securities included in cash and cash equivalents in our condensed consolidated balance sheets.
	(c)	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.
	(d)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.
Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation
		Commodity Derivative Instruments
		Current			Long-			Current			Long-
		Assets			Term			Liabilities			Term
					Assets						Liabilities
		(Millions)
	Three months ended March 31, 2015 (a):
	Beginning balance	$	138		$	18		$	—		$	—
	Net unrealized gains (losses) included in earnings (b)	20			(18		)	—			—
	Settlements	(40		)	—			—			—
	Ending balance	$	118		$	—		$	—		$	—
	Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	20		$	(18	)	$	—		$	—
	Three months ended March 31, 2014 (a):
	Beginning balance	$	65		$	75		$	—		$	—
	Net unrealized gains (losses) included in earnings (b)	17			(15		)	(1		)	—
	Settlements	(12		)	—			—			—
	Ending balance	$	70		$	60		$	(1	)	$	—
	Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	19		$	(15	)	$	(1	)	$	—
	(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 2015 and 2014.
	(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.
Schedule of Valuation Processes
		31-Mar-15
	Product Group	Fair Value			Forward
					Curve Range
		(Millions)
	Assets
	NGLs	$	118		$0.17-$1.12		Per gallon
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	As of March 31, 2015 and December 31, 2014, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, were as follows:
			31-Mar-15						31-Dec-14
			Carrying Value			Fair Value			Carrying Value			Fair Value
		(Millions)
	Senior Notes		$	2,312		$	2,157		$	2,311		$	2,334

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Schedule of Debt
		March 31,			December 31,
		2015			2014
		(Millions)
	Debt Securities
	Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015	250			250
	Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
	Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019	325			325
	Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
	Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			500
	Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044	400			400
	Unamortized discount	(13		)	(14		)
	Total debt	2,312			2,311
	Current maturities of long-term debt	(250		)	(250		)
	Total long-term debt	$	2,062		$	2,061
Future Maturities of Long-Term Debt	The future maturities of long-term debt in the year indicated are as follows:
		Debt
		Maturities
		(Millions)
	2016	$	—
	2017	500
	2018	—
	2019	325
	2020	—
	Thereafter	1,250
		2,075
	Unamortized discount	(13		)
	Total	$	2,062

Risk_Management_and_Hedging_Ac2

Risk Management and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Gross and Net Amounts of Derivative Instruments	The following summarizes the gross and net amounts of our derivative instruments:
		31-Mar-15												31-Dec-14
		Gross Amounts				Amounts Not				Net				Gross Amounts				Amounts Not			Net
		of Assets and				Offset in the				Amount				of Assets and				Offset in the			Amount
		(Liabilities)				Balance Sheet -								(Liabilities)				Balance Sheet -
		Presented in the				Financial								Presented in the				Financial
		Balance Sheet				Instruments (a)								Balance Sheet				Instruments (a)
		(Millions)
	Assets:
	Commodity derivatives	$	216			$	(32	)		$	184			$	269			$	(42	)	$	227
	Liabilities:
	Commodity derivatives	$	(33	)		$	32			$	(1	)		$	(43	)		$	42		$	(1	)
	(a)	There is no cash collateral pledged or received against these positions.
Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value	The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2015 and December 31, 2014.
	Balance Sheet Line Item	March 31,				December 31,				Balance Sheet Line Item		March 31,				December 31,
		2015				2014						2015				2014
		(Millions)										(Millions)
	Derivative Assets Not Designated as Hedging Instruments:									Derivative Liabilities Not Designated as Hedging Instruments:
	Commodity derivatives:									Commodity derivatives:
	Unrealized gains on derivative instruments — current	$	196			$	230			Unrealized losses on derivative instruments — current		$	(33	)		$	(43	)
	Unrealized gains on derivative instruments — long-term	20				39				Unrealized losses on derivative instruments — long-term		—				—
		$	216			$	269					$	(33	)		$	(43	)
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2015:
		Interest						Commodity				Foreign				Total
		Rate Cash						Cash Flow				Currency
		Flow						Hedges				Cash Flow
		Hedges										Hedges (a)
		(Millions)
	Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)				$	(6	)		$	1			$	(9	)
	Losses reclassified from AOCI to earnings — effective portion	1				(b)		—				—				1
	Net deferred (losses) gains in AOCI (ending balance)	$	(3	)				$	(6	)		$	1			$	(8	)
	Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)				$	—			$	—			$	(1	)
	(a)	Relates to Discovery, our unconsolidated affiliate.
	(b)	Included in interest expense in our condensed consolidated statements of operations.
	The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2014:
		Interest						Commodity				Foreign				Total
		Rate Cash						Cash Flow				Currency
		Flow						Hedges				Cash Flow
		Hedges										Hedges (a)
		(Millions)
	Net deferred (losses) gains in AOCI (beginning balance)	$	(6	)				$	(6	)		$	1			$	(11	)
	Losses reclassified from AOCI to earnings — effective portion	$	2			(b)		$	—			$	—			$	2
	Net deferred (losses) gains in AOCI (ending balance)	$	(4	)				$	(6	)		$	1			$	(9	)
	(a)	Relates to Discovery, our unconsolidated affiliate.
	(b)	Included in interest expense in our condensed consolidated statements of operations.
Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments	The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected:
	Commodity Derivatives: Statements of Operations Line Item	Three Months Ended March 31,
		2015				2014
		(Millions)
	Third party:
	Realized gains (losses)	$	7			$	(3	)
	Unrealized losses	(2		)		—
	Gains (losses) from commodity derivative activity, net	$	5			$	(3	)
	Affiliates:
	Realized gains	$	54			$	1
	Unrealized losses	(40		)		(13		)
	Gains (losses) from commodity derivative activity, net —affiliates	$	14			$	(12	)
	Interest Rate Derivatives: Statements of Operations Line Item	Three Months Ended March 31,
		2015				2014
		(Millions)
	Third party:
	Realized losses	$	—			$	(1	)
	Unrealized gains	—				1
	Interest expense	$	—			$	—
Schedule of Net Long or Short Positions Expected to be Realized	The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below.
		31-Mar-15
		Crude Oil			Natural Gas			Natural Gas			Natural Gas
								Liquids			Basis Swaps
	Year of Expiration	Net (Short)			Net			Net			Net Long Position
		Position			(Short)			(Short)			(MMBtu)
		(Bbls)			Position			Position
					(MMBtu)			(Bbls)
	2015	(561,825	)		(12,429,125	)		(4,231,200	)		2,675,000
	2016	(561,922	)		(5,668,564	)		(813,267	)		1,690,000
	2017	—			(6,387,500	)		—			—
		31-Mar-14
		Crude Oil			Natural Gas			Natural Gas			Natural Gas
								Liquids			Basis Swaps
	Year of Expiration	Net (Short)			Net (Short)			Net (Short)			Net Long
		Position			Position			Position			Position
		(Bbls)			(MMBtu)			(Bbls)			(MMBtu)
	2014	(520,575	)		(4,014,200	)		(4,602,350	)		4,305,000
	2015	(745,695	)		(13,458,975	)		(5,691,570	)		2,185,000
	2016	(561,922	)		(3,668,564	)		(813,267	)		—
	2017	—			(6,387,500	)		—			—

Partnership_Equity_and_Distrib1

Partnership Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Cash Distribution	The following table presents our cash distributions paid in 2015 and 2014:
	Payment Date	Per Unit		Total Cash
		Distribution		Distribution
				(Millions)
	February 13, 2015	$	0.78	$	120
	November 14, 2014	$	0.77	$	117
	August 14, 2014	$	0.7575	$	111
	May 15, 2014	$	0.745	$	106
	February 14, 2014	$	0.7325	$	86

Business_Segments_Tables

Business Segments (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Information	The following tables set forth our segment information:
	Three Months Ended March 31, 2015:
		Natural Gas			NGL			Wholesale			Other			Total
		Services			Logistics			Propane
								Logistics
		(Millions)
	Total operating revenue	$	440		$	18		$	110		$	—		$	568
	Gross margin (a)	$	119		$	18		$	29		$	—		$	166
	Operating and maintenance expense	(40		)	(4		)	(3		)	—			(47		)
	Depreciation and amortization expense	(26		)	(2		)	(1		)	—			(29		)
	General and administrative expense	—			—			—			(21		)	(21		)
	Earnings from unconsolidated affiliates	(2		)	25			—			—			23
	Interest expense	—			—			—			(22		)	(22		)
	Income tax expense	—			—			—			(1		)	(1		)
	Net income (loss)	$	51		$	37		$	25		$	(44	)	$	69
	Net income attributable to noncontrolling interests	—			—			—			—			—
	Net income (loss) attributable to partners	$	51		$	37		$	25		$	(44	)	$	69
	Non-cash derivative mark-to-market (b)	$	(45	)	$	—		$	3		$	(1	)	$	(43	)
	Non-cash lower of cost or market adjustments	$	3		$	—		$	1		$	—		$	4
	Capital expenditures	$	50		$	13		$	2		$	—		$	65
	Investments in unconsolidated affiliates	$	12		$	13		$	—		$	—		$	25
	Three Months Ended March 31, 2014:
		Natural Gas			NGL			Wholesale			Other			Total
		Services (c)			Logistics			Propane
								Logistics
		(Millions)
	Total operating revenue	$	849		$	17		$	215		$	—		$	1,081
	Gross margin (a)	$	164		$	17		$	15		$	—		$	196
	Operating and maintenance expense	(38		)	(4		)	(3		)	—			(45		)
	Depreciation and amortization expense	(24		)	(1		)	(1		)	—			(26		)
	General and administrative expense	—			—			—			(16		)	(16		)
	Other expense	(1		)	—			—			—			(1		)
	Earnings from unconsolidated affiliates	(1		)	4			—			—			3
	Interest expense	—			—			—			(19		)	(19		)
	Income tax expense	—			—			—			(3		)	(3		)
	Net income (loss)	$	100		$	16		$	11		$	(38	)	$	89
	Net income attributable to noncontrolling interests	(10		)	—			—			—			(10		)
	Net income (loss) attributable to partners	$	90		$	16		$	11		$	(38	)	$	79
	Non-cash derivative mark-to-market (b)	$	(12	)	$	—		$	(1	)	$	(1	)	$	(14	)
	Non-cash lower of cost or market adjustments	$	—		$	—		$	3		$	—		$	3
	Capital expenditures	$	55		$	4		$	4		$	—		$	63
	Acquisition expenditures	$	100		$	669		$	—		$	—		$	769
	Investments in unconsolidated affiliates	$	42		$	23		$	—		$	—		$	65
		March 31,			December 31,
		2015			2014
		(Millions)
	Segment long-term assets:
	Natural Gas Services	$	4,364		$	3,609
	NGL Logistics	651			1,364
	Wholesale Propane Logistics	121			118
	Other (d)	38			58
	Total long-term assets	5,174			5,149
	Current assets	470			590
	Total assets	$	5,644		$	5,739
	(a)	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
	(b)	Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.
	(c)	The segment information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information, similar to the pooling method.
	(d)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	3 Months Ended
	Mar. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Summary of Supplemental Cash Flow Information
		Three Months Ended March 31,
		2015		2014
		(Millions)
	Cash paid for interest:
	Cash paid for interest, net of amounts capitalized	$	8	$	10
	Non-cash investing and financing activities:
	Property, plant and equipment acquired with accounts payable	$	32	$	12
	Other non-cash changes in property, plant and equipment	$	—	$	—
	Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions	$	—	$	81
	Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$	—	$	144

Supplementary_Information_Cond1

Supplementary Information - Condensed Consolidating Financial Information (Tables)	3 Months Ended
	Mar. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets
		Condensed Consolidating Balance Sheet
		31-Mar-15
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	—			$	32			$	1		$	—		$	33
	Accounts receivable, net	—				—				203			—			203
	Inventories	—				—				36			—			36
	Other	—				—				198			—			198
	Total current assets	—				32				438			—			470
	Property, plant and equipment, net	—				—				3,374			—			3,374
	Goodwill and intangible assets, net	—				—				271			—			271
	Advances receivable — consolidated subsidiaries	2,521				1,946				—			(4,467		)	—
	Investments in consolidated subsidiaries	453				803				—			(1,256		)	—
	Investments in unconsolidated affiliates	—				—				1,481			—			1,481
	Other long-term assets	—				17				31			—			48
	Total assets	$	2,974			$	2,798			$	5,595		$	(5,723	)	$	5,644
	LIABILITIES AND EQUITY
	Accounts payable and other current liabilities	$	—			$	283			$	242		$	—		$	525
	Advances payable — consolidated subsidiaries	—				—				4,467			(4,467		)	—
	Long-term debt	—				2,062				—			—			2,062
	Other long-term liabilities	—				—				51			—			51
	Total liabilities	—				2,345				4,760			(4,467		)	2,638
	Commitments and contingent liabilities
	Equity:
	Partners’ equity:
	Net equity	2,974				456				808			(1,256		)	2,982
	Accumulated other comprehensive loss	—				(3		)		(5		)	—			(8		)
	Total partners’ equity	2,974				453				803			(1,256		)	2,974
	Noncontrolling interests	—				—				32			—			32
	Total equity	2,974				453				835			(1,256		)	3,006
	Total liabilities and equity	$	2,974			$	2,798			$	5,595		$	(5,723	)	$	5,644
		Condensed Consolidating Balance Sheet
		December 31, 2014
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	—			$	24			$	1		$	—		$	25
	Accounts receivable, net	—				—				270			—			270
	Inventories	—				—				63			—			63
	Other	—				—				232			—			232
	Total current assets	—				24				566			—			590
	Property, plant and equipment, net	—				—				3,347			—			3,347
	Goodwill and intangible assets, net	—				—				274			—			274
	Advances receivable — consolidated subsidiaries	2,610				1,962				—			(4,572		)	—
	Investments in consolidated subsidiaries	383				712				—			(1,095		)	—
	Investments in unconsolidated affiliates	—				—				1,459			—			1,459
	Other long-term assets	—				17				52			—			69
	Total assets	$	2,993			$	2,715			$	5,698		$	(5,667	)	$	5,739
	LIABILITIES AND EQUITY
	Accounts payable and other current liabilities	$	—			$	271			$	330		$	—		$	601
	Advances payable — consolidated subsidiaries	—				—				4,572			(4,572		)	—
	Long-term debt	—				2,061				—			—			2,061
	Other long-term liabilities	—				—				51			—			51
	Total liabilities	—				2,332				4,953			(4,572		)	2,713
	Commitments and contingent liabilities
	Equity:
	Partners’ equity:
	Net equity	2,993				387				717			(1,095		)	3,002
Accumulated other comprehensive loss	—				(4		)		(5		)	—			(9		)
Total partners’ equity	2,993				383				712			(1,095		)	2,993
Noncontrolling interests	—				—				33			—			33
Total equity	2,993				383				745			(1,095		)	3,026
Total liabilities and equity	$	2,993			$	2,715			$	5,698		$	(5,667	)	$	5,739
Condensed Income Statement [Table Text Block]
		Condensed Consolidating Statement of Operations
		Three Months Ended March 31, 2014 (a)
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	Operating revenues:
	Sales of natural gas, propane, NGLs and condensate	$	—			$	—			$	1,013		$	—		$	1,013
	Transportation, processing and other	—				—				83			—			83
	Gains from commodity derivative activity, net	—				—				(15		)	—			(15		)
	Total operating revenues	—				—				1,081			—			1,081
	Operating costs and expenses:
	Purchases of natural gas, propane and NGLs	—				—				885			—			885
	Operating and maintenance expense	—				—				45			—			45
	Depreciation and amortization expense	—				—				26			—			26
	General and administrative expense	—				—				16			—			16
	Other expense	—				—				1			—			1
	Total operating costs and expenses	—				—				973			—			973
	Operating income	—				—				108			—			108
	Interest expense	—				(19		)		—			—			(19		)
	Earnings from unconsolidated affiliates	—				—				3			—			3
	Income from consolidated subsidiaries	79				98				—			(177		)	—
	Income before income taxes	79				79				111			(177		)	92
	Income tax expense	—				—				(3		)	—			(3		)
	Net income	79				79				108			(177		)	89
	Net income attributable to noncontrolling interests	—				—				(10		)	—			(10		)
	Net income attributable to partners	$	79			$	79			$	98		$	(177	)	$	79
	(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.
		Condensed Consolidating Statement of Operations
		Three Months Ended March 31, 2015
		Parent				Subsidiary				Non-			Consolidating			Consolidated
		Guarantor				Issuer				Guarantor			Adjustments
										Subsidiaries
		(Millions)
	Operating revenues:
	Sales of natural gas, propane, NGLs and condensate	$	—			$	—			$	470		$	—		$	470
	Transportation, processing and other	—				—				79			—			79
	Gains from commodity derivative activity, net	—				—				19			—			19
	Total operating revenues	—				—				568			—			568
	Operating costs and expenses:
	Purchases of natural gas, propane and NGLs	—				—				402			—			402
	Operating and maintenance expense	—				—				47			—			47
	Depreciation and amortization expense	—				—				29			—			29
	General and administrative expense	—				—				21			—			21
	Total operating costs and expenses	—				—				499			—			499
	Operating income	—				—				69			—			69
	Interest expense, net	—				(22		)		—			—			(22		)
	Income from consolidated subsidiaries	69				91				—			(160		)	—
	Earnings from unconsolidated affiliates	—				—				23			—			23
	Income before income taxes	69				69				92			(160		)	70
	Income tax expense	—				—				(1		)	—			(1		)
	Net income	69				69				91			(160		)	69
	Net income attributable to noncontrolling interests	—				—				—			—			—
	Net income attributable to partners	$	69			$	69			$	91		$	(160	)	$	69
Condensed Statement of Comprehensive Income [Table Text Block]
		Condensed Consolidating Statement of Comprehensive Income
		Three Months Ended March 31, 2014 (a)
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	Net income	$	79			$	79			$	108		$	(177	)	$	89
	Other comprehensive income:
	Reclassification of cash flow hedge losses into earnings	—				2				—			—			2
	Other comprehensive income from consolidated subsidiaries	2				—				—			(2		)	—
	Total other comprehensive income	2				2				—			(2		)	2
	Total comprehensive income	81				81				108			(179		)	91
	Total comprehensive income attributable to noncontrolling interests	—				—				(10		)	—			(10		)
	Total comprehensive income attributable to partners	$	81			$	81			$	98		$	(179	)	$	81
	(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.
		Condensed Consolidating Statement of Comprehensive Income
		Three Months Ended March 31, 2015
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	Net income	$	69			$	69			$	91		$	(160	)	$	69
	Other comprehensive income:
	Reclassification of cash flow hedge losses into earnings	—				1				—			—			1
	Other comprehensive income from consolidated subsidiaries	1				—				—			(1		)	—
	Total other comprehensive income	1				1				—			(1		)	1
	Total comprehensive income	70				70				91			(161		)	70
	Total comprehensive income attributable to noncontrolling interests	—				—				—			—			—
	Total comprehensive income attributable to partners	$	70			$	70			$	91		$	(161	)	$	70
Condensed Consolidating Statements of Cash Flows
		Condensed Consolidating Statement of Cash Flows
		Three Months Ended March 31, 2015
		Parent			Subsidiary			Non-Guarantor			Consolidating		Consolidated
		Guarantor			Issuer			Subsidiaries			Adjustments
		(Millions)
	OPERATING ACTIVITIES
	Net cash (used in) provided by operating activities	—			(8	)		196			—		188
	INVESTING ACTIVITIES:
	Intercompany transfers	89			16			—			(105	)	—
	Capital expenditures	—			—			(65	)		—		(65	)
	Investments in unconsolidated affiliates	—			—			(25	)		—		(25	)
	Net cash used in investing activities	89			16			(90	)		(105	)	(90	)
	FINANCING ACTIVITIES:
	Intercompany transfers	—			—			(105	)		105		—
	Proceeds from long-term debt	—			162			—			—		162
	Payments of long-term debt	—			(162	)		—			—		(162	)
	Proceeds from issuance of common units, net of offering costs	31			—			—			—		31
	Distributions to limited partners and general partner	(120	)		—			—			—		(120	)
	Distributions to noncontrolling interests	—			—			(1	)		—		(1	)
	Net cash used in financing activities	(89	)		—			(106	)		105		(90	)
	Net change in cash and cash equivalents	—			8			—			—		8
	Cash and cash equivalents, beginning of period	—			24			1			—		25
	Cash and cash equivalents, end of period	—			32			1			—		33
		Condensed Consolidating Statements of Cash Flows
		Three Months Ended March 31, 2014 (a)
		Parent				Subsidiary				Non-Guarantor			Consolidating			Consolidated
		Guarantor				Issuer				Subsidiaries			Adjustments
		(Millions)
	OPERATING ACTIVITIES
	Net cash (used in) provided by operating activities	$	—			$	(11	)		$	157		$	—		$	146
	INVESTING ACTIVITIES:
	Intercompany transfers	(591		)		(365		)		—			956			—
	Capital expenditures	—				—				(63		)	—			(63		)
	Acquisitions, net of cash acquired	—				—				(100		)	—			(100		)
	Acquisition of unconsolidated affiliates	—				—				(669		)	—			(669		)
	Investments in unconsolidated affiliates	—				—				(65		)	—			(65		)
	Proceeds from sale of assets	—				—				1			—			1
	Net cash used in investing activities	(591		)		(365		)		(896		)	956			(896		)
	FINANCING ACTIVITIES:
	Intercompany transfers	—				—				956			(956		)	—
	Proceeds from long-term debt	—				719				—			—			719
	Payments of long-term debt	—				(314		)		—			—			(314		)
	Payment of deferred financing costs	—				(6		)		—			—			(6		)
	Proceeds from issuance of common units, net of offering costs	677				—				—			—			677
	Excess purchase price over acquired interests and commodity hedges	—				—				(14		)	—			(14		)
	Net change in advances to predecessor from DCP Midstream, LLC	—				—				(6		)	—			(6		)
	Distributions to limited partners and general partner	(86		)		—				—			—			(86		)
	Distributions to noncontrolling interests	—				—				(10		)	—			(10		)
	Purchase of additional interest in a subsidiary	—				—				(198		)	—			(198		)
	Contributions from noncontrolling interests	—				—				3			—			3
	Net cash provided by financing activities	591				399				731			(956		)	765
	Net change in cash and cash equivalents	—				23				(8		)	—			15
	Cash and cash equivalents, beginning of period	—				—				12			—			12
	Cash and cash equivalents, end of period	$	—			$	23			$	4		$	—		$	27
	(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.

Description_of_Business_and_Ba2

Description of Business and Basis of Presentation - Additional Information (Detail)	Dec. 31, 2014
Business Acquisition [Line Items]
Ownership interest percentage by parent	100.00%
Investments in Greater Than 20% [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Investments in Less Than 20% [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Phillips 66 [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%
Spectra Energy [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%
DCP Midstream, LLC [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent	21.40%

Acquisitions_Additional_Inform

Acquisitions - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
	mi
	MBbls
Panola [Member]
Business Acquisition [Line Items]
Aggregate consideration for acquisition	$1
Capacity per day	50
Expected capacity per day	100
Business Acquisition, Percentage of Voting Interests Acquired	15.00%
Pipeline Length In Miles	180
Other JV Partners [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	15.00%
Operator [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	55.00%
Scenario, Forecast [Member] | Panola [Member]
Business Acquisition [Line Items]
Aggregate consideration for acquisition	$26
Pipeline Length In Miles	60

Agreements_and_Transactions_wi2

Agreements and Transactions with Affiliates - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Transportation, processing and other	$79	$83
Affiliated Entity [Member] | DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	23	18
Affiliated Entity [Member] | Lucerne 1 [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	3
Affiliated Entity [Member] | O'Connor Plant [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	$9	$7

Agreements_and_Transactions_wi3

Agreements and Transactions with Affiliates - Schedule of Fees Incurred and Other Fees Paid (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Services/Omnibus Agreement	$18	$7
Other fees - DCP Midstream, LLC	0	4
Total - DCP Midstream, LLC	21	16
Services Agreement Amendment Increase	25
Related Party Transaction, Amounts of Transaction	71
DCP Midstream, LLC [Member] | Affiliated Entity [Member]
Total - DCP Midstream, LLC	18	11
Eagle Ford System [Member]
Other fees - DCP Midstream, LLC		4
Maximum [Member] | DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC	$1	$1

Agreements_and_Transactions_wi4

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	$470	$1,013
Transportation, processing and other	79	83
Purchases of natural gas, propane and NGLs	402	885
Gain (Loss) on Derivative Instruments, Net, Pretax	19	-15
Operating and maintenance expense	47	45
General and administrative expense	21	16
Affiliated Entity [Member] | DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	281	642
Transportation, processing and other	23	18
Purchases of natural gas, propane and NGLs	25	80
General and administrative expense	18	11
Affiliated Entity [Member] | DCP Midstream, LLC [Member] | Commodity Derivatives [Member]
Related Party Transaction [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	14	-12
Affiliated Entity [Member] | Spectra Energy [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	0	14
Purchases of natural gas, propane and NGLs	$10	$20

Agreements_and_Transactions_wi5

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Related Party Transaction [Line Items]
Accounts receivable	$130	$164
Accounts payable	26	27
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Accounts receivable	130	163
Accounts payable	21	24
Unrealized gains on derivative instruments - current	32	207
Unrealized gains on derivative instruments - long-term	7	25
Unrealized losses on derivative instruments - current	33	43
Spectra Energy [Member]
Related Party Transaction [Line Items]
Accounts receivable	0	1
Accounts payable	$5	$3

Inventories_Schedule_of_Invent

Inventories - Schedule of Inventories (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Components Of Inventory [Line Items]
Total inventories	$36	$63
Natural Gas [Member]
Components Of Inventory [Line Items]
Total inventories	21	36
Natural Gas Liquids [Member]
Components Of Inventory [Line Items]
Total inventories	$15	$27

Inventories_Additional_Informa

Inventories - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Inventory Disclosure [Abstract]
Inventory Write-down	$4	$3

Property_Plant_and_Equipment_C

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	4,664	$4,611
Accumulated depreciation	-1,290	-1,264
Property, plant and equipment, net	3,374	3,347
Gathering and Transmission Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,267	2,209
Gathering and Transmission Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	20 years
Gathering and Transmission Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	50 years
Processing, Storage, and Terminal Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,042	2,071
Processing, Storage, and Terminal Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	35 years
Processing, Storage, and Terminal Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	60 years
Other Energy Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	55	50
Other Energy Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	3 years
Other Energy Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	30 years
Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	300	$281

Property_Plant_and_Equipment_A

Property, Plant and Equipment - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Property, Plant and Equipment [Line Items]
Interest capitalized on construction projects	$3	$1
Depreciation expense	$26	$24

Recovered_Sheet1

Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$1,481	$1,459
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	427	413
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Investments in unconsolidated affiliates	413	406
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	327	329
Front Range Pipeline LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	171	169
Texas Express Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Investments in unconsolidated affiliates	98	98
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	12.50%
Investments in unconsolidated affiliates	24	23
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Investments in unconsolidated affiliates	13	14
Other [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage description	Various
Investments in unconsolidated affiliates	$8	$7

Investments_in_Unconsolidated_2

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$23	$3
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	11	0
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	1	1
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	3	0
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	4	4
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	-2	-1
Texas Express [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	2	0
Front Range [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$4	($1)

Investments_in_Unconsolidated_3

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$233	$111
Operating expenses	129	82
Net income	$103	$29

Investments_in_Unconsolidated_4

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$200	$207
Long-term assets	5,270	5,157
Current liabilities	-195	-200
Long-term liabilities	-239	-164
Net assets	$5,036	$5,000

Fair_Value_Measurement_Financi

Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	$33		$24
Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	196	[1]	230	[1]
Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	20	[2]	39	[2]
Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	-33	[3]	-43	[3]
Level 1 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	33		24
Level 1 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	[1]	0	[1]
Level 1 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	[2]	0	[2]
Level 1 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	[3]	0	[3]
Level 2 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	0		0
Level 2 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	78	[1]	92	[1]
Level 2 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	20	[2]	21	[2]
Level 2 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	-33	[3]	-43	[3]
Level 3 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	0		0
Level 3 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	118	[1]	138	[1]
Level 3 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	[2]	18	[2]
Level 3 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	$0	[3]	$0	[3]
[1]	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.
[2]	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.
[3]	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.

Fair_Value_Measurement_Condens

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Current Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$138	[1]	$65	[1]
Net realized and unrealized gains (losses) included in earnings	20	[1],[2]	17	[1],[2]
Settlements	-40	[1]	-12	[1]
Ending balance	118	[1]	70	[1]
Net unrealized gains still held included in earnings	20	[1],[2]	19	[1],[2]
Long-Term Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	18	[1]	75	[1]
Net realized and unrealized gains (losses) included in earnings	-18	[1],[2]	-15	[1],[2]
Settlements	0	[1]	0	[1]
Ending balance	0	[1]	60	[1]
Net unrealized gains still held included in earnings	-18	[1],[2]	-15	[1],[2]
Current Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	[1]	0	[1]
Net realized and unrealized (losses) gains included in earnings	0	[1],[2]	-1	[1],[2]
Settlements	0	[1]	0	[1]
Ending balance	0	[1]	-1	[1]
Net unrealized gains (losses) still held included in earnings	0	[1],[2]	-1	[1],[2]
Long-Term Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	[1]	0	[1]
Net realized and unrealized (losses) gains included in earnings	0	[1],[2]	0	[1],[2]
Settlements	0	[1]	0	[1]
Ending balance	0	[1]	0	[1]
Net unrealized gains (losses) still held included in earnings	$0	[1],[2]	$0	[1],[2]
[1]	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended MarchB 31, 2015 and 2014.
[2]	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Fair_Value_Measurement_Schedul

Fair Value Measurement - Schedule of Valuation Processes (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Fair Value, Assets	118
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range		0.17
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range		1.12
Senior Notes, 3.25% Due 2015 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.25%	3.25%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	2.50%	2.50%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage		5.60%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage		2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	4.95%	4.95%
Senior Notes, 3.875% Due 2023 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.88%	3.88%
Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range		0
Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range		0

Fair_Value_Measurement_Additio

Fair Value Measurement - Additional Information (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Carrying Amount	$2,312	$2,311
Debt Instrument, Fair Value	$2,157	$2,334
Senior Notes, 3.875% Due 2023 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage	3.88%	3.88%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage	2.50%	2.50%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage		2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage	4.95%	4.95%
Senior Notes, 3.25% Due 2015 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage	3.25%	3.25%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage		5.60%

Debt_Schedule_of_LongTerm_Debt

Debt - Schedule of Long-Term Debt (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Line of Credit Facility [Line Items]
Long-term Debt, Current Maturities	$250	$250
Unamortized discount	-13	-14
Total	2,312	2,311
Total long-term debt	2,062	2,061
Senior Notes, 3.875% Due 2023 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	500	500
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	400	400
Senior Notes, 2.50% Due 2017 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	500	500
Senior Notes, 4.95% Due 2022 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	350	350
Senior Notes, 3.25% Due 2015 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	250	250
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	$325	$325

Debt_Schedule_of_LongTerm_Debt1

Debt - Schedule of Long-Term Debt (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maturity date	10-Nov-16
Senior Notes, 3.875% Due 2023 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage	3.88%	3.88%
Maturity date	15-Mar-23
Senior Notes, 2.50% Due 2017 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage	2.50%	2.50%
Maturity date	1-Dec-17
Senior Notes, 4.95% Due 2022 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage	4.95%	4.95%
Maturity date	1-Apr-22
Senior Notes, 3.25% Due 2015 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage	3.25%	3.25%
Maturity date	1-Oct-15

Debt_Additional_Information_De

Debt - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Proceeds from long-term debt	$162,000,000	$719,000,000
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Senior notes issued	325,000,000		325,000,000
Senior notes interest rate percentage			2.70%
Proceeds from long-term debt		320,000,000
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Debt Instrument [Line Items]
Senior notes issued	400,000,000		400,000,000
Senior notes interest rate percentage			5.60%
Proceeds from long-term debt		392,000,000
Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Senior notes issued	500,000,000		500,000,000
Senior notes interest rate percentage	3.88%		3.88%
Maturity date	15-Mar-23
Senior Notes, 2.50% Due 2017 [Member]
Debt Instrument [Line Items]
Senior notes issued	500,000,000		500,000,000
Senior notes interest rate percentage	2.50%		2.50%
Maturity date	1-Dec-17
Senior Notes, 4.95% Due 2022 [Member]
Debt Instrument [Line Items]
Senior notes issued	350,000,000		350,000,000
Senior notes interest rate percentage	4.95%		4.95%
Maturity date	1-Apr-22
Senior Notes, 3.25% Due 2015 [Member]
Debt Instrument [Line Items]
Senior notes issued	250,000,000		250,000,000
Senior notes interest rate percentage	3.25%		3.25%
Maturity date	1-Oct-15
Eagle Ford System [Member] | Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			46.67%
Amended and Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			1,000,000,000
Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maturity date	10-Nov-16
Unused capacity under the credit agreement	1,249,000,000
Basis spread determined by credit rating	0.45%
Commitment fee percentage	0.30%
London Interbank Offered Rate (LIBOR) [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.45%
Federal Funds Effective Swap Rate [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
London Interbank Offered Rate (LIBOR) Market Index [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of credit issued		1,000,000
Letters of credit outstanding	1,100,000		1,000,000
Minimum [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	5
Temporary maximum leverage ratio post-acquisition	5.5
Maximum [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	1
Temporary maximum leverage ratio post-acquisition	1
Pro Forma [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Unused capacity under the credit agreement	$1,205,000,000

Debt_Future_Maturities_of_Long

Debt - Future Maturities of Long-Term Debt (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Maturities of Long-term Debt [Abstract]
2014	$0
2015	500
2016	0
2017	325
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Thereafter	1,250
Total principal	2,075
Unamortized discount	-13	-14
Total	$2,062

Risk_Management_and_Hedging_Ac3

Risk Management and Hedging Activities - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Accumulated other comprehensive loss	($8)		($9)
Notional value of derivative			150
Interest rate swap agreements reprice every thirty days	30 days
Effective fixed-rates lower range			2.94%
Effective fixed-rates higher range			2.99%
Common unitholders, units issued	114,738,148		113,949,868
Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	-1
Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring		1
Interest Rate Swap [Member]
Derivative [Line Items]
Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring	1
Cash Flow Hedge [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	-8	-9	-9	-11
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	-6	-6	-6	-6
Cash Flow Hedge [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	($3)	($4)	($4)	($6)
Limited Partner [Member]
Derivative [Line Items]
Common unitholders, units issued		14,375,000
Senior Notes, 4.95% Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.95%		4.95%

Risk_Management_and_Hedging_Ac4

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) (Commodity Derivatives [Member], USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Commodity Derivatives [Member]
Fair Values Of Financial Assets And Liabilities Including Derivative Financial Instruments [Line Items]
Gross Amounts of Assets Presented in the Balance Sheet	$216		$269
Amounts Not Offset in the Balance Sheet - Financial Instruments	-32	[1]	-42	[1]
Net Amount, Assets	184		227
Gross Amounts of Liabilities Presented in the Balance Sheet	-33		-43
Amounts Not Offset in the Balance Sheet - Financial Instruments	32	[1]	42	[1]
Net Amount, Liabilities	$1		$1
[1]	There is no cash collateral pledged or received against these positions.

Risk_Management_and_Hedging_Ac5

Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	$196	$230
Unrealized gains on derivative instruments - long-term	20	39
Commodity Derivatives [Member] | Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	196	230
Unrealized gains on derivative instruments - long-term	20	39
Derivative assets, fair value, total	216	269
Commodity Derivatives [Member] | Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	33	43
Unrealized losses on derivative instruments - long-term	0	0
Derivative liabilities, fair value, total	($33)	($43)

Risk_Management_and_Hedging_Ac6

Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)					($9)
Net deferred losses in AOCI (ending balance)	-8				-9
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	-9		-11
Gains (losses) recognized in AOCI on derivatives - effective portion	1		2
Net deferred losses in AOCI (ending balance)	-8		-9
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-1
Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	-4		-6
Gains (losses) recognized in AOCI on derivatives - effective portion	1	[1]	2	[1]
Net deferred losses in AOCI (ending balance)	-3		-4
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-1
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	-6		-6
Gains (losses) recognized in AOCI on derivatives - effective portion	0		0
Net deferred losses in AOCI (ending balance)	-6		-6
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	0
Cash Flow Hedge [Member] | Foreign Currency Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	1	[2]	1
Gains (losses) recognized in AOCI on derivatives - effective portion	0	[2]	0	[2]
Net deferred losses in AOCI (ending balance)	1	[2]	1	[2]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$0	[2]
[1]	Included in interest expense in our condensed consolidated statements of operations.
[2]	Relates to Discovery, our unconsolidated affiliate.

Risk_Management_and_Hedging_Ac7

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Parenthetical) (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Interest Rate Derivatives [Member]
Derivative [Line Items]
Gain/Loss Reclassified From AOCI to Earnings-Discontinuance	$1
Commodity Derivatives [Member]
Derivative [Line Items]
Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing	1
Gain/Loss Reclassified From AOCI to Earnings-Discontinuance		$1

Risk_Management_and_Hedging_Ac8

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Accumulated other comprehensive loss	($8)				($9)
Commodity Derivatives [Member]
Derivative [Line Items]
Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing	-1
Cash Flow Hedge [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	-8		-9		-9		-11
Losses Reclassified From AOCI to Earnings-Effective Portion	1		2
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-1
Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	-3		-4		-4		-6
Losses Reclassified From AOCI to Earnings-Effective Portion	1	[1]	2	[1]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-1
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	-6		-6		-6		-6
Losses Reclassified From AOCI to Earnings-Effective Portion	0		0
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	0
Cash Flow Hedge [Member] | Foreign Currency Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	1	[2]	1	[2]	1	[2]	1
Losses Reclassified From AOCI to Earnings-Effective Portion	0	[2]	0	[2]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$0	[2]
[1]	Included in interest expense in our condensed consolidated statements of operations.
[2]	Relates to Discovery, our unconsolidated affiliate.

Risk_Management_and_Hedging_Ac9

Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) (Derivative Assets Not Designated As Hedging Instruments [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Affiliates [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Realized	$54	$1
Unrealized	-40	-13
(Losses) gains from commodity derivative activity, net	14	-12
Third Party [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Realized	7	-3
Unrealized	-2	0
(Losses) gains from commodity derivative activity, net	5	-3
Third Party [Member] | Interest Rate Derivatives [Member]
Derivative [Line Items]
Realized		-1
Unrealized		$1

Recovered_Sheet2

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
	bbl	bbl
Crude Oil [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013		-520,575
Net (Short) Position (Bbls), 2014	-561,825	-745,695
Net (Short) Position (Bbls), 2015	-561,922	-561,922
Net (Short) Position (Bbls), 2016	0	0
Natural Gas [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013		-4,014,200
Net Long (Short) Position (MMBtu), 2014	-12,429,125	-13,458,975
Net Long (Short) Position (MMBtu), 2015	-5,668,564	-3,668,564
Net Long (Short) Position (MMBtu), 2016	-6,387,500	-6,387,500
Natural Gas Liquids [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013		4,602,350
Net (Short) Position (Bbls), 2014	-4,231,200	-5,691,570
Net (Short) Position (Bbls), 2015	-813,267	-813,267
Net (Short) Position (Bbls), 2016	0	0
Natural Gas Basis Swaps [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013		4,305,000
Net Long (Short) Position (MMBtu), 2014	2,675,000	2,185,000
Net Long (Short) Position (MMBtu), 2015	1,690,000	0
Net Long (Short) Position (MMBtu), 2016	0	0

Partnership_Equity_and_Distrib2

Partnership Equity and Distributions - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2015	Dec. 31, 2014
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued		114,738,148	113,949,868
Issuance of common units	14,375,000
Consideration financed through issuance of common units	4,497,158
Sand Hills Pipeline [Member]
Partnership Equity And Distribution [Line Items]
Equity Method Investment, Ownership Percentage		33.33%
2014 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued		788,033
Proceeds from issuance of common stock		$31
Offering costs		1
Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Offer value of common stock remaining available for sale		349
Limited Partners [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued	14,375,000
Issuance of common units	14,375,000	788,033
Price per common unit	48.9
Net proceeds	677

Partnership_Equity_and_Distrib3

Partnership Equity and Distributions - Cash Distribution (Detail) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Partnership Equity And Distribution [Line Items]
Total Cash Distribution (Millions)	$120	$86
February Thirteen Two Thousand Fifteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$0.78
Total Cash Distribution (Millions)	120
November Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$0.77
Total Cash Distribution (Millions)	117
August Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$0.76
Total Cash Distribution (Millions)	111
May Fifteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$0.75
Total Cash Distribution (Millions)	106
February Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$0.73
Total Cash Distribution (Millions)	$86

Net_Income_or_Loss_per_Limited1

Net Income or Loss per Limited Partner Unit - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Weighted Average Number Diluted Limited Partnership Units Outstanding Adjustment	11,573	9,742

Business_Segments_Additional_I

Business Segments - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014		Dec. 31, 2014
	Project	Project
	Segment
Segment Reporting Information [Line Items]
Total operating revenues	$568	$1,081
Number of reporting segments	3
Ownership interest percentage				100.00%
Number of owned and operated rail terminals	6
Number of owned marine import terminals	1
Number of leased marine terminals	1
Pipeline Terminals		1
Gross margin	166	196	[1]
Other Cost and Expense, Operating	-47	-45
Depreciation, Depletion and Amortization, Nonproduction	-29	-26
General and Administrative Expense	-21	-16
Earnings from unconsolidated affiliates	23	3
Interest expense	-22	-19
Income tax expense	-1	-3
Net income	69	89
Net income attributable to noncontrolling interests	0	-10
Net Income (Loss) Attributable to Parent	69	79
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-43	-14
Capital expenditures	65	63
Acquisition expenditures		769
Investments in unconsolidated affiliates	25	65
Natural Gas Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues	440	849
Gross margin	119	164
Other Cost and Expense, Operating	-40	-38
Depreciation, Depletion and Amortization, Nonproduction	-26	-24
General and Administrative Expense	0	0
Earnings from unconsolidated affiliates	-2	-1
Interest expense	0	0
Income tax expense	0	0
Net income	51	100
Net income attributable to noncontrolling interests	0	-10
Net Income (Loss) Attributable to Parent	51	90
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-45	-12
Capital expenditures	50	55
Acquisition expenditures		100
Investments in unconsolidated affiliates	12	42
Colorado [Member]
Segment Reporting Information [Line Items]
Ownership interest percentage				75.00%
Discovery Producer Services LLC [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				40.00%
Mont Belvieu 1 Fractionator [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				20.00%
Mont Belvieu Enterprise Fractionator [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				12.50%
Texas Express [Member]
Segment Reporting Information [Line Items]
Ownership interest percentage in subsidiary		10.00%
NGL Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues	18	17
Gross margin	18	17
Other Cost and Expense, Operating	-4	-4
Depreciation, Depletion and Amortization, Nonproduction	-2	-1
General and Administrative Expense	0	0
Earnings from unconsolidated affiliates	25	4
Interest expense	0	0
Income tax expense	0	0
Net income	37	16
Net income attributable to noncontrolling interests	0	0
Net Income (Loss) Attributable to Parent	37	16
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	0	0
Capital expenditures	13	4
Acquisition expenditures		669
Investments in unconsolidated affiliates	13	23
Wholesale Propane Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues	110	215
Gross margin	29	15
Other Cost and Expense, Operating	-3	-3
Depreciation, Depletion and Amortization, Nonproduction	-1	-1
General and Administrative Expense	0	0
Earnings from unconsolidated affiliates	0	0
Interest expense	0	0
Income tax expense	0	0
Net income	25	11
Net income attributable to noncontrolling interests	0	0
Net Income (Loss) Attributable to Parent	25	11
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	3	-1
Capital expenditures	2	4
Acquisition expenditures		0
Investments in unconsolidated affiliates	0	0
Other [Member]
Segment Reporting Information [Line Items]
Total operating revenues	0	0
Gross margin	0	0	[1]
Other Cost and Expense, Operating	0	0
Depreciation, Depletion and Amortization, Nonproduction	0	0
General and Administrative Expense	-21	-16
Earnings from unconsolidated affiliates	0	0
Interest expense	-22	-19
Income tax expense	-1	-3
Net income	-44	-38
Net income attributable to noncontrolling interests	0	0
Net Income (Loss) Attributable to Parent	-44	-38
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-1	-1
Capital expenditures	0	0
Acquisition expenditures		0
Investments in unconsolidated affiliates	$0	$0
[1]	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

Business_Segments_Segment_Info

Business Segments - Segment Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014		Dec. 31, 2014
Segment Reporting Information [Line Items]
Total operating revenues	$568	$1,081
Gross margin	166	196	[1]
Operating and maintenance expense	-47	-45
Depreciation and amortization expense	-29	-26
General and administrative expense	-21	-16
Earnings from unconsolidated affiliates	23	3
Other operating income	0	1
Interest expense	-22	-19
Income tax expense	-1	-3
Net income	69	89
Net income attributable to noncontrolling interests	0	-10
Net income attributable to partners	69	79
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-43	-14
Non-cash lower of cost or market adjustments	4	3
Capital expenditures	65	63
Acquisition expenditures		769
Investments in unconsolidated affiliates	25	65
Total long-term assets	5,174			5,149
Current assets	470			590
Total assets	5,644			5,739
Natural Gas Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues	440	849
Gross margin	119	164
Operating and maintenance expense	-40	-38
Depreciation and amortization expense	-26	-24
General and administrative expense	0	0
Earnings from unconsolidated affiliates	-2	-1
Other operating income		-1
Interest expense	0	0
Income tax expense	0	0
Net income	51	100
Net income attributable to noncontrolling interests	0	-10
Net income attributable to partners	51	90
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-45	-12
Non-cash lower of cost or market adjustments	3	0
Capital expenditures	50	55
Acquisition expenditures		100
Investments in unconsolidated affiliates	12	42
Total long-term assets	4,364			3,609
NGL Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues	18	17
Gross margin	18	17
Operating and maintenance expense	-4	-4
Depreciation and amortization expense	-2	-1
General and administrative expense	0	0
Earnings from unconsolidated affiliates	25	4
Other operating income		0
Interest expense	0	0
Income tax expense	0	0
Net income	37	16
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	37	16
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	0	0
Non-cash lower of cost or market adjustments	0	0
Capital expenditures	13	4
Acquisition expenditures		669
Investments in unconsolidated affiliates	13	23
Total long-term assets	651			1,364
Wholesale Propane Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues	110	215
Gross margin	29	15
Operating and maintenance expense	-3	-3
Depreciation and amortization expense	-1	-1
General and administrative expense	0	0
Earnings from unconsolidated affiliates	0	0
Other operating income		0
Interest expense	0	0
Income tax expense	0	0
Net income	25	11
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	25	11
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	3	-1
Non-cash lower of cost or market adjustments	1	3
Capital expenditures	2	4
Acquisition expenditures		0
Investments in unconsolidated affiliates	0	0
Total long-term assets	121			118
Other [Member]
Segment Reporting Information [Line Items]
Total operating revenues	0	0
Gross margin	0	0	[1]
Operating and maintenance expense	0	0
Depreciation and amortization expense	0	0
General and administrative expense	-21	-16
Earnings from unconsolidated affiliates	0	0
Other operating income		0
Interest expense	-22	-19
Income tax expense	-1	-3
Net income	-44	-38
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	-44	-38
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-1	-1
Non-cash lower of cost or market adjustments	0	0
Capital expenditures	0	0
Acquisition expenditures		0
Investments in unconsolidated affiliates	0	0
Total long-term assets	$38			$58
[1]	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

Business_Segments_Segment_Info1

Business Segments - Segment Information (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	Project	Project
Segment Reporting Information [Line Items]
Number of owned and operated rail terminals	6
Ownership interest percentage			100.00%
Number of owned marine import terminals	1
Marine Terminals	1
Pipeline Terminals		1

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$8	$10
Property, plant and equipment acquired with accounts payable	32	12
Other non-cash additions of property, plant and equipment	0	0
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	0	81
Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$0	$144

Supplementary_Information_Cond2

Supplementary Information - Condensed Consolidating Financial Information - Additional Information (Detail) (Parent Guarantor [Member])	3 Months Ended
	Mar. 31, 2015
Parent Guarantor [Member]
Parent Company Only Financial Information [Line Items]
Ownership interest percentage in subsidiary	100.00%

Supplementary_Information_Cond3

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
ASSETS
Cash and cash equivalents	$33	$25	$27	$12
Accounts receivable, net	203	270
Inventories	36	63
Other	198	232
Total current assets	470	590
Property, plant and equipment, net	3,374	3,347
Goodwill and intangible assets, net	271	274
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,481	1,459
Other long-term assets	48	69
Total assets	5,644	5,739
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	525	601
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,062	2,061
Other long-term liabilities	51	51
Total liabilities	2,638	2,713
Commitments and contingent liabilities
Equity:
Net equity	2,982	3,002
Accumulated other comprehensive loss	-8	-9
Total partners' equity	2,974	2,993
Noncontrolling interests	32	33
Total equity	3,006	3,026	2,711	2,213
Total liabilities and equity	5,644	5,739
Parent Guarantor [Member]
ASSETS
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	2,521	2,610
Investments in consolidated subsidiaries	453	383
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	2,974	2,993
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Advances payable - consolidated subsidiaries	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	0	0
Commitments and contingent liabilities
Equity:
Net equity	2,974	2,993
Accumulated other comprehensive loss	0	0
Total partners' equity	2,974	2,993
Noncontrolling interests	0	0
Total equity	2,974	2,993
Total liabilities and equity	2,974	2,993
Subsidiary Issuer [Member]
ASSETS
Cash and cash equivalents	32	24	23	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	32	24
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	1,946	1,962
Investments in consolidated subsidiaries	803	712
Investments in unconsolidated affiliates	0	0
Other long-term assets	17	17
Total assets	2,798	2,715
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	283	271
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,062	2,061
Other long-term liabilities	0	0
Total liabilities	2,345	2,332
Commitments and contingent liabilities
Equity:
Net equity	456	387
Accumulated other comprehensive loss	-3	-4
Total partners' equity	453	383
Noncontrolling interests	0	0
Total equity	453	383
Total liabilities and equity	2,798	2,715
Non-Guarantor Subsidiaries [Member]
ASSETS
Cash and cash equivalents	1	1	4	12
Accounts receivable, net	203	270
Inventories	36	63
Other	198	232
Total current assets	438	566
Property, plant and equipment, net	3,374	3,347
Goodwill and intangible assets, net	271	274
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,481	1,459
Other long-term assets	31	52
Total assets	5,595	5,698
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	242	330
Advances payable - consolidated subsidiaries	4,467	4,572
Long-term debt	0	0
Other long-term liabilities	51	51
Total liabilities	4,760	4,953
Commitments and contingent liabilities
Equity:
Net equity	808	717
Accumulated other comprehensive loss	-5	-5
Total partners' equity	803	712
Noncontrolling interests	32	33
Total equity	835	745
Total liabilities and equity	5,595	5,698
Consolidating Adjustments [Member]
ASSETS
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	-4,467	-4,572
Investments in consolidated subsidiaries	-1,256	-1,095
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	-5,723	-5,667
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Advances payable - consolidated subsidiaries	-4,467	-4,572
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	-4,467	-4,572
Commitments and contingent liabilities
Equity:
Net equity	-1,256	-1,095
Accumulated other comprehensive loss	0	0
Total partners' equity	-1,256	-1,095
Noncontrolling interests	0	0
Total equity	-1,256	-1,095
Total liabilities and equity	($5,723)	($5,667)

Supplementary_Information_Cond4

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate	$470	$1,013
Transportation, processing and other	79	83
Gain (Loss) on Derivative Instruments, Net, Pretax	19	-15
Total operating revenues	568	1,081
Purchases of natural gas, propane and NGLs	402	885
Operating and maintenance expense	47	45
Depreciation and amortization expense	29	26
General and administrative expense	21	16
Other expense (income)	0	1
Total operating costs and expenses	499	973
Operating Income (Loss)	69	108
Interest expense	-22	-19
Income from consolidated subsidiaries	0	0
Earnings from unconsolidated affiliates	23	3
Income before income taxes	70	92
Income tax expense	-1	-3
Net income	69	89
Net income attributable to noncontrolling interests	0	-10
Net income attributable to partners	69	79
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate	0	0
Transportation, processing and other	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Total operating revenues	0	0
Purchases of natural gas, propane and NGLs	0	0
Operating and maintenance expense	0	0
Depreciation and amortization expense	0	0
General and administrative expense	0	0
Other expense (income)		0
Total operating costs and expenses	0	0
Operating Income (Loss)	0	0
Interest expense	0	0
Income from consolidated subsidiaries	69	79
Earnings from unconsolidated affiliates	0	0
Income before income taxes	69	79
Income tax expense	0	0
Net income	69	79
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	69	79
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate	0	0
Transportation, processing and other	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Total operating revenues	0	0
Purchases of natural gas, propane and NGLs	0	0
Operating and maintenance expense	0	0
Depreciation and amortization expense	0	0
General and administrative expense	0	0
Other expense (income)		0
Total operating costs and expenses	0	0
Operating Income (Loss)	0	0
Interest expense	-22	-19
Income from consolidated subsidiaries	91	98
Earnings from unconsolidated affiliates	0	0
Income before income taxes	69	79
Income tax expense	0	0
Net income	69	79
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	69	79
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate	470	1,013
Transportation, processing and other	79	83
Gain (Loss) on Derivative Instruments, Net, Pretax	19	-15
Total operating revenues	568	1,081
Purchases of natural gas, propane and NGLs	402	885
Operating and maintenance expense	47	45
Depreciation and amortization expense	29	26
General and administrative expense	21	16
Other expense (income)		1
Total operating costs and expenses	499	973
Operating Income (Loss)	69	108
Interest expense	0	0
Income from consolidated subsidiaries	0	0
Earnings from unconsolidated affiliates	23	3
Income before income taxes	92	111
Income tax expense	-1	-3
Net income	91	108
Net income attributable to noncontrolling interests	0	-10
Net income attributable to partners	91	98
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate	0	0
Transportation, processing and other	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Total operating revenues	0	0
Purchases of natural gas, propane and NGLs	0	0
Operating and maintenance expense	0	0
Depreciation and amortization expense	0	0
General and administrative expense	0	0
Other expense (income)		0
Total operating costs and expenses	0	0
Operating Income (Loss)	0	0
Interest expense	0	0
Income from consolidated subsidiaries	-160	-177
Earnings from unconsolidated affiliates	0	0
Income before income taxes	-160	-177
Income tax expense	0	0
Net income	-160	-177
Net income attributable to noncontrolling interests	0	0
Net income attributable to partners	($160)	($177)

Supplementary_Information_Cond5

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Net income	$69	$89
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	1	2
Other comprehensive income from consolidated subsidiaries	0	0
Total other comprehensive income	1	2
Total comprehensive income	70	91
Total comprehensive income (loss) attributable to noncontrolling interests	0	-10
Total comprehensive income attributable to partners	70	81
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	69	79
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	0	0
Other comprehensive income from consolidated subsidiaries	1	2
Total other comprehensive income	1	2
Total comprehensive income	70	81
Total comprehensive income (loss) attributable to noncontrolling interests	0	0
Total comprehensive income attributable to partners	70	81
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	69	79
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	1	2
Other comprehensive income from consolidated subsidiaries	0	0
Total other comprehensive income	1	2
Total comprehensive income	70	81
Total comprehensive income (loss) attributable to noncontrolling interests	0	0
Total comprehensive income attributable to partners	70	81
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	91	108
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	0	0
Other comprehensive income from consolidated subsidiaries	0	0
Total other comprehensive income	0	0
Total comprehensive income	91	108
Total comprehensive income (loss) attributable to noncontrolling interests	0	-10
Total comprehensive income attributable to partners	91	98
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	-160	-177
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	0	0
Other comprehensive income from consolidated subsidiaries	-1	-2
Total other comprehensive income	-1	-2
Total comprehensive income	-161	-179
Total comprehensive income (loss) attributable to noncontrolling interests	0	0
Total comprehensive income attributable to partners	($161)	($179)

Supplementary_Information_Cond6

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$188	$146
Payments for (Proceeds from) Other Investing Activities	0	0
INVESTING ACTIVITIES:
Capital expenditures	-65	-63
Acquisitions, net of cash acquired	0	-100
Payments to Acquire Equity Method Investments	0	-669
Investments in unconsolidated affiliates	25	65
Proceeds from sales of assets	0	1	[1]
Net cash used in investing activities	-90	-896
Proceeds from (Payments for) Other Financing Activities	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	162	719
Repayments of Long-term Debt	162	0
Payments of commercial paper, net	0	-314
Payments of deferred financing costs	0	-6
Excess purchase price over acquired net assets and commodity hedge	0	-14
Proceeds from issuance of common units, net of offering cost	31	677
Excess Purchase Price Over Acquired Assets		-158
Net change in advances to predecessor from DCP Midstream, LLC	0	-6
Payments of Ordinary Dividends	-120	-86
Distributions to noncontrolling interests	-1	-10
Payments to Noncontrolling Interests	0	-198
Contributions from noncontrolling interests	0	3
Payments of Capital Distribution	120	86
Net cash (used in) provided by financing activities	-90	765
Net change in cash and cash equivalents	8	15
Cash and cash equivalents, beginning of period	25	12
Cash and cash equivalents, end of period	33	27
Parent Guarantor [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0
Payments for (Proceeds from) Other Investing Activities	89	-591
INVESTING ACTIVITIES:
Capital expenditures	0	0
Acquisitions, net of cash acquired		0
Payments to Acquire Equity Method Investments		0
Investments in unconsolidated affiliates	0	0
Proceeds from sales of assets		0	[1]
Net cash used in investing activities	89	-591
Proceeds from (Payments for) Other Financing Activities	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0
Repayments of Long-term Debt	0
Payments of commercial paper, net		0
Payments of deferred financing costs		0
Excess purchase price over acquired net assets and commodity hedge		0
Proceeds from issuance of common units, net of offering cost	31	677
Net change in advances to predecessor from DCP Midstream, LLC		0
Payments of Ordinary Dividends	-120	-86
Distributions to noncontrolling interests	0	0
Contributions from noncontrolling interests		0
Net cash (used in) provided by financing activities	-89	591
Net change in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	0	0
Subsidiary Issuer [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	-8	-11
Payments for (Proceeds from) Other Investing Activities	16	-365
INVESTING ACTIVITIES:
Capital expenditures	0	0
Acquisitions, net of cash acquired		0
Payments to Acquire Equity Method Investments		0
Investments in unconsolidated affiliates	0	0
Proceeds from sales of assets		0	[1]
Net cash used in investing activities	16	-365
Proceeds from (Payments for) Other Financing Activities	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	162	719
Repayments of Long-term Debt	162
Payments of commercial paper, net		-314
Payments of deferred financing costs		-6
Excess purchase price over acquired net assets and commodity hedge		0
Proceeds from issuance of common units, net of offering cost	0	0
Net change in advances to predecessor from DCP Midstream, LLC		0
Payments of Ordinary Dividends	0	0
Distributions to noncontrolling interests	0	0
Contributions from noncontrolling interests		0
Net cash (used in) provided by financing activities	0	399
Net change in cash and cash equivalents	8	23
Cash and cash equivalents, beginning of period	24	0
Cash and cash equivalents, end of period	32	23
Non-Guarantor Subsidiaries [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	196	157
Payments for (Proceeds from) Other Investing Activities	0	0
INVESTING ACTIVITIES:
Capital expenditures	-65	-63
Acquisitions, net of cash acquired		-100
Payments to Acquire Equity Method Investments		-669
Investments in unconsolidated affiliates	25	65
Proceeds from sales of assets		1	[1]
Net cash used in investing activities	-90	-896
Proceeds from (Payments for) Other Financing Activities	-105	956
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0
Repayments of Long-term Debt	0
Payments of commercial paper, net		0
Payments of deferred financing costs		0
Excess purchase price over acquired net assets and commodity hedge		-14
Proceeds from issuance of common units, net of offering cost	0	0
Net change in advances to predecessor from DCP Midstream, LLC		-6
Payments of Ordinary Dividends	0	0
Distributions to noncontrolling interests	-1	-10
Contributions from noncontrolling interests		3
Net cash (used in) provided by financing activities	-106	731
Net change in cash and cash equivalents	0	-8
Cash and cash equivalents, beginning of period	1	12
Cash and cash equivalents, end of period	1	4
Consolidating Adjustments [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0
Payments for (Proceeds from) Other Investing Activities	-105	956
INVESTING ACTIVITIES:
Capital expenditures	0	0
Acquisitions, net of cash acquired		0
Payments to Acquire Equity Method Investments		0
Investments in unconsolidated affiliates	0	0
Proceeds from sales of assets		0	[1]
Net cash used in investing activities	-105	956
Proceeds from (Payments for) Other Financing Activities	105	-956
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0
Repayments of Long-term Debt	0
Payments of commercial paper, net		0
Payments of deferred financing costs		0
Excess purchase price over acquired net assets and commodity hedge		0
Proceeds from issuance of common units, net of offering cost	0	0
Net change in advances to predecessor from DCP Midstream, LLC		0
Payments of Ordinary Dividends	0	0
Distributions to noncontrolling interests	0	0
Contributions from noncontrolling interests		0
Net cash (used in) provided by financing activities	105	-956
Net change in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	$0	$0
[1]	(a)The financial information for the three months ended MarchB 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method.

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Mar. 31, 2015	Dec. 31, 2014	Apr. 28, 2015
		mi
		MBbls
Subsequent Event [Line Items]
Common unitholders, units issued		114,738,148	113,949,868
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution of dividend				$0.78
Distribution payable date	15-May-15
Distribution record date	8-May-15
Equity Distribution Agreement [Member]
Subsequent Event [Line Items]
Offer value of common stock remaining available for sale		$349
Panola [Member]
Subsequent Event [Line Items]
Pipeline Length In Miles		180
Expected capacity per day		100
Aggregate consideration for acquisition		$1