Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Feb. 19, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	DPM
Entity Registrant Name	DCP MIDSTREAM PARTNERS, LP
Entity Central Index Key	0001338065
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		113,950,115
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 4,878,338,000

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 25	$ 12
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1 million	106	130
Affiliates	164	212
Inventories	63	67
Unrealized gains on derivative instruments	230	79
Other	2	3
Total current assets	590	503
Property, plant and equipment, net	3,347	3,046
Goodwill	154	154
Intangible assets, net	120	129
Investments in unconsolidated affiliates	1,459	627
Unrealized gains on derivative instruments	39	87
Other long-term assets	30	21
Total assets	5,739	4,567
Accounts payable:
Trade	196	232
Affiliates	27	43
Short-term borrowings	0	335
Long-term Debt, Current Maturities	250	0
Unrealized losses on derivative instruments	43	28
Other	85	85
Total current liabilities	601	723
Long-term debt	2,061	1,590
Unrealized losses on derivative instruments	0	1
Other long-term liabilities	51	40
Total liabilities	2,713	2,354
Commitments and contingent liabilities
Equity:
Predecessor equity	0	40
Limited partners (113,949,868 and 89,045,139 common units issued and outstanding, respectively)	2,984	1,948
General partner	18	8
Accumulated other comprehensive loss	(9)	(11)
Total partners' equity	2,993	1,985
Noncontrolling interests	33	228
Total equity	3,026	2,213
Total liabilities and equity	$ 5,739	$ 4,567

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Allowance for doubtful accounts	$ 1	$ 1
Common unitholders, units issued	113,949,868	89,045,139
Common unitholders, units outstanding	113,949,868	89,045,139

Consolidated Statements of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$ 3,143	$ 2,763	$ 2,520
Transportation, processing and other	345	271	234
Gain (Loss) on Derivative Instruments, Net, Pretax	154	17	70
Total operating revenues	3,642	3,051	2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,795	2,426	2,215
Operating and maintenance expense	216	215	197
Depreciation and amortization expense	110	95	91
General and administrative expense	64	63	75
Other expense (income)	3	8	0
Total operating costs and expenses	3,188	2,807	2,578
Operating Income (Loss)	454	244	246
Interest expense	(86)	(52)	(42)
Earnings from unconsolidated affiliates	75	33	26
Income before income taxes	443	225	230
Income tax expense	(6)	(8)	(1)
Net income	437	217	229
Net income attributable to noncontrolling interests	(14)	(17)	(13)
Net income attributable to partners	423	200	216
Net income attributable to predecessor operations	(6)	(25)	(51)
General partner's interest in net income	(114)	(70)	(41)
Net income allocable to limited partners	303	105	124
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 2.84	$ 1.34	$ 2.28
Weighted Average Limited Partnership Units Outstanding, Basic	106.60	78.40	54.50
Weighted Average Limited Partnership Units Outstanding, Diluted	106.60	78.40	54.50
Third Party [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	963	932	820
Transportation, processing and other	239	211	179
Gain (Loss) on Derivative Instruments, Net, Pretax	36	(5)	17
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,524	2,159	1,807
General and administrative expense	17	17	17
Affiliated Entity [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	2,180	1,831	1,700
Transportation, processing and other	106	60	55
Gain (Loss) on Derivative Instruments, Net, Pretax	118	22	53
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	271	267	408
General and administrative expense	$ 47	$ 46	$ 58

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Predecessor, Net of Tax	$ 0	$ 0	$ (1)
Net income	437	217	229
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	2	4	10
Total other comprehensive income	2	4	9
Total comprehensive income	439	221	238
Total comprehensive income attributable to noncontrolling interests	(14)	(17)	(13)
Total comprehensive income attributable to partners	$ 425	$ 204	$ 225

Consolidated Statements of Changes in Equity (USD $) In Millions	Total	Lucerne 1 [Member]	Eagle Ford System [Member]	Southeast Texas and NGL Hedge [Member]	Southeast Texas [Member]	East Texas [Member]	Mont Belvieu Fractionators [Member]	Eagle Ford System and Commodity Hedge [Member]	Eagle Ford System and NGL Hedge [Member]	Predecessor Equity [Member]	Predecessor Equity [Member] Lucerne 1 [Member]	Predecessor Equity [Member] Eagle Ford System [Member]	Predecessor Equity [Member] Southeast Texas and NGL Hedge [Member]	Limited Partners [Member]	Limited Partners [Member] Eagle Ford System [Member]	Limited Partners [Member] Southeast Texas and NGL Hedge [Member]	Limited Partners [Member] Southeast Texas [Member]	Limited Partners [Member] East Texas [Member]	Limited Partners [Member] Mont Belvieu Fractionators [Member]	Limited Partners [Member] Eagle Ford System and Commodity Hedge [Member]	Limited Partners [Member] Eagle Ford System and NGL Hedge [Member]	General Partner [Member]	General Partner [Member] Eagle Ford System [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Accumulated Other Comprehensive (Loss) Income [Member] Eagle Ford System [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member] Eagle Ford System [Member]	Noncontrolling Interests [Member] East Texas [Member]
Beginning balance at Dec. 31, 2011	$ 1,605									$ 671				$ 654								$ (5)		$ (21)		$ 306
Net income	229	18								51				124								41				13
Other comprehensive (loss) income	9									(1)														10
Partners Capital Net Change In Parent Advances To Predecessor	(221)									(181)																(40)
Partners Capital Account Acquisitions Issuance Of Units			88		48	33	60								88		48	33	60
Deficit purchase price under carrying value of acquired net assets	32													36										(4)
Excess purchase price over carrying value of acquired net assets			(42)				(175)		(156)			(23)			(9)				(175)		(156)						(10)
Issuance of common units	455													455
Distributions to limited partners and general partner	(181)													(145)								(36)
Distributions to noncontrolling interests	(9)																									(9)
Contributions from noncontrolling interests	25																									25
Contributions from DCP Midstream, LLC	10													10
Payments to Acquire Equity Method Investments			(232)									(232)
Partners Capital Account Acquisition Of Additional Interest In Subsidiary				208		176							248			(40)												176
Ending balance at Dec. 31, 2012	1,636									399				1,063								0		(15)		189
Net income	217	19								25				105								70				17
Other comprehensive (loss) income	4									0														4
Partners Capital Net Change In Parent Advances To Predecessor	11									11
Partners' Capital Account, Acquisitions			(395)									(395)			0								0		0		0
Partners Capital Account Acquisitions Issuance Of Units			125												125
Excess purchase price over carrying value of acquired net assets								(203)	(7)											(203)	(7)
Issuance of common units	1,082													1,082
Distributions to limited partners and general partner	(277)													(215)								(62)
Distributions to noncontrolling interests	(24)																									(24)
Contributions from noncontrolling interests	46																									46
Contributions from DCP Midstream, LLC	1													1
Distributions to DCP Midstream, LLC	(3)													(3)
Payments to Acquire Equity Method Investments	86
Ending balance at Dec. 31, 2013	2,213									40				1,948								8		(11)		228
Net income	437									6				303								114				14
Other comprehensive (loss) income	2																							2
Partners Capital Net Change In Parent Advances To Predecessor	(6)									(6)
Partners' Capital Account, Acquisitions		(40)									(40)
Acquisition of additional interest in subsidiary			(198)																								(198)
Partners Capital Account Acquisitions Issuance Of Units			225												225
Excess purchase price over carrying value of acquired net assets			(178)												(178)
Issuance of common units	1,002													1,002
Distributions to limited partners and general partner	(420)													(316)								(104)
Distributions to noncontrolling interests	(14)																									(14)
Contributions from noncontrolling interests	3																									3
Payments to Acquire Equity Method Investments	673
Ending balance at Dec. 31, 2014	$ 3,026									$ 0				$ 2,984								$ 18		$ (9)		$ 33

Consolidated Statements of Changes in Equity (Parenthetical)	12 Months Ended					1 Months Ended				1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014 Limited Partners [Member]	Dec. 31, 2013 Limited Partners [Member]	Dec. 31, 2012 Limited Partners [Member]	Mar. 31, 2013 Eagle Ford System [Member]	Nov. 30, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Eagle Ford System [Member]	Mar. 14, 2013 Eagle Ford System [Member]	Mar. 31, 2012 Southeast Texas [Member]	Mar. 13, 2012 Southeast Texas [Member]
Consideration financed through issuance of common units			4,497,158			2,789,739	1,912,663			1,000,417
Business Acquisition, Percentage of Voting Interests Acquired						46.67%	33.33%	20.00%	46.67%	66.67%	66.67%
Issuance of common units	24,897,977	11,285,956	20,407,571	24,897,977	11,285,956

Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING ACTIVITIES:
Net income	$ 437	$ 217	$ 229
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	110	95	91
Earnings from unconsolidated affiliates	(75)	(33)	(26)
Distributions from unconsolidated affiliates	120	39	24
Net unrealized (gains) losses on derivative instruments	(86)	36	(21)
Other, net	14	19	3
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable	68	(89)	(11)
Inventories	4	9	14
Accounts payable	(67)	51	(194)
Accrued interest	8	5	5
Other current assets and liabilities	(5)	(2)	(4)
Other long-term assets and liabilities	(4)	(2)	(8)
Net cash provided by operating activities	524	345	102
INVESTING ACTIVITIES:
Capital expenditures	(338)	(363)	(484)
Acquisitions, net of cash acquired	(102)	(696)	(433)
Acquisition of unconsolidated affiliates	(673)	(86)	(312)
Investments in unconsolidated affiliates	(151)	(242)	(158)
Return of investment from unconsolidated affiliate	0	0	1
Proceeds from sales of assets	28	0	2
Net cash used in investing activities	(1,236)	(1,387)	(1,384)
FINANCING ACTIVITIES:
Proceeds from long-term debt	719	1,957	2,665
Payments of long-term debt	0	(1,988)	(1,792)
(Payments) proceeds of commercial paper, net	(335)	335	0
Payments of deferred financing costs	(7)	(4)	(8)
Excess purchase price over acquired interests and commodity hedges	(18)	(85)	(225)
Proceeds from issuance of common units, net of offering costs	1,001	1,083	455
Net change in advances to predecessor from DCP Midstream, LLC	(6)	11	336
Distributions to limited partners and general partner	(420)	(277)	(181)
Distributions to noncontrolling interests	(14)	(24)	(9)
Purchase of additional interest in a subsidiary	(198)	0	0
Contributions from noncontrolling interests	3	46	25
Payments Of Distributions To Parent	0	(3)	0
Contributions from DCP Midstream, LLC	0	1	10
Net cash provided by financing activities	725	1,052	1,276
Net change in cash and cash equivalents	13	10	(6)
Cash and cash equivalents, beginning of period	12	2	8
Cash and cash equivalents, end of period	$ 25	$ 12	$ 2

Description of Business and Basis of Presentation	12 Months Ended
Description of Business and Basis of Presentation	Dec. 31, 2014
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 18 - 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 21.5% of us, including its limited partner and general partner interests. The 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. All intercompany balances and transactions have been eliminated. Our predecessor results consist of the Lucerne 1 plant, which we acquired from DCP Midstream, LLC in March 2014, an 80% interest in the Eagle Ford system, of which we acquired 46.67% and 33.33% from DCP Midstream, LLC in March 2013 and November 2012, respectively, and a 66.67% interest in the Southeast Texas system, which we acquired from DCP Midstream, LLC in March 2012. Prior to our acquisition of the additional 46.67% interest in the Eagle Ford system in March 2013, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to the March 2013 transaction, but prior to the acquisition of the remaining 20% interest in March 2014, we owned 80% of the Eagle Ford system which we accounted for as a consolidated subsidiary. These transfers of net assets between entities under common control were accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of our Lucerne 1 plant, our initial 80% interest in the Eagle Ford system and the remaining 66.67% interest in the Southeast Texas system for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in excess or in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction or an addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. In addition, the results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates.

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References+ Details

Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Summary of Significant Accounting Policies

Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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.

Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents.

Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.

Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchase or normal sale exception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:



Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Cash Flow Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (b)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

Other Non-Trading Derivative Activity	Mark-to-market method (c)	Net basis in gains and losses from commodity derivative activity

______________

(a)

Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.


(b)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.


(c)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.

Valuation - 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 relationships with quoted market prices and the 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.

Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.

Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled.

Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill at the reporting unit level during the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

Investments in Unconsolidated Affiliates - We use the equity method to account for 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.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:


•	significant adverse change in legal factors or business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;


•	a significant adverse change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Unamortized Debt Discount and Expense - Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The discounts are recorded on the consolidated balance sheets within the carrying amount of long-term debt. The unamortized expenses are recorded on the consolidated balance sheet as other long-term assets.

Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors.

Revenue Recognition - We generate the majority of our revenues from gathering, compressing, treating, processing, transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by receiving fees. We also generate revenue from transporting, storing and selling propane.

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

•

Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

•

Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.


•	Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their customers.

Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:


•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.


•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.


•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. We recognize revenues for non-trading commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity derivative activity. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial and physical energy trading contracts.

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash.

Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2014, 2013 and 2012. We had significant transactions with affiliates.

Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities included in the consolidated balance sheets as other current liabilities was $1 million, and other long-term liabilities was $1 million at both December 31, 2014 and 2013.

Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal returns of each partner.

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 limited partner unit 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.

- Definition

The entire disclosure for all significant accounting policies of the reporting entity.

+ References+ Details

Acquisitions

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisitions

On March 31, 2014, DCP Midstream, LLC and its affiliates contributed to us: (i) a 33.33% membership interest in DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (ii) a 33.33% membership interest in DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline; and (iii) the remaining 20% interest in DCP SC Texas GP, or the Eagle Ford system. The Sand Hills pipeline is engaged in the business of transporting NGLs and consists of approximately 1,025 miles of pipe, with a capacity of 200 MBbls/d, and possible further capacity increases with the installation of additional pump stations. The Sand Hills pipeline provides NGL takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and at the Mont Belvieu, Texas market hub. The Sand Hills pipeline began taking flows in the fourth quarter of 2012 and was placed into service in June 2013. The Southern Hills pipeline is also engaged in the business of transporting NGLs and consists of approximately 940 miles of pipe, with a capacity of 175 MBbls/d. The Southern Hills pipeline provides NGL takeaway service from the Midcontinent to fractionation facilities at the Mont Belvieu, Texas market hub. The Southern Hills pipeline began taking flows in the first quarter of 2013 and was placed into service in June 2013.

On March 28, 2014, we acquired from DCP Midstream, LLC and its affiliates (i) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (ii) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, or the Lucerne 2 plant, which is currently under construction. The Lucerne 1 plant and Lucerne 2 plant, along with our O'Connor plant, comprises our DJ Basin system. In conjunction with our acquisition of the Lucerne 1 plant, we entered into a long-term fee-based processing agreement with DCP Midstream, LLC pursuant to which DCP Midstream, LLC agreed to pay us (i) a fixed demand charge of 75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for DCP Midstream, LLC at the Lucerne 1 plant. The Lucerne 2 plant is expected to be completed in the second quarter of 2015 and we have assumed all of the remaining costs to complete this project. In addition, we entered into a ten-year, fee-based natural gas processing agreement with DCP Midstream, LLC that is effective once the Lucerne 2 plant is placed into service. At that time, the processing agreement with Lucerne 1 will be terminated. The new processing agreement initially provided a fixed demand charge on 75% of the capacity of and a throughput fee on all volumes processed at both plants once the Lucerne 2 plant is placed into service. In December 2014, we amended the agreement to provide a fixed demand charge on 43% of the capacity of both plants from the time that the Lucerne 2 plant is placed into service through the remainder of 2015 which was the original intent of the parties. Thereafter, the agreement will resume a fixed demand charge on 75% of the capacity of both plants. Except with respect to the fixed demand charge, there were no other changes to the agreement as a result of the December 2014 amendment. Together with the contribution of the interests in the Sand Hills and Southern Hills pipelines and the remaining 20% interest in the Eagle Ford system, the acquisition of the Lucerne 1 and 2 plants are collectively referred to hereafter as the March 2014 Transactions.

Total consideration for the March 2014 Transactions at closing was $1,220 million, less customary working capital and other adjustments. $225 million of the consideration was funded by the issuance at closing of 2,098,674 of our common units to DCP Midstream, LLC, 1,399,116 of our common units to DCP LP Holdings, LLC, and 999,368 of our common units to DCP Midstream GP, LP. The remainder of the consideration was financed by a portion of the issuance of 14,375,000 common units to the public and the proceeds from our 5.60% 30-year Senior Notes and 2.70% five-year Senior Notes offering. The total consideration over the carrying value of the net assets of the Sand Hills and Southern Hills pipelines, the remaining 20% of the Eagle Ford system, and the Lucerne 1 and Lucerne 2 plants resulted in an excess purchase price of $178 million which was recorded as a decrease in limited partners' equity in the consolidated statement of changes in equity.

The acquisition of the Lucerne 2 plant and contribution of the interests in the Sand Hills pipeline, the Southern Hills pipeline and the remaining 20% interest in the Eagle Ford system represent a transfer of assets between entities under common control. The results for these entities are included prospectively from the date of acquisition or contribution. The acquisition of the Lucerne 1 plant represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated financial statements have been adjusted to retrospectively include the historical results of the Lucerne 1 plant for all periods presented, similar to the pooling method. The results of the Sand Hills and Southern Hills pipelines are included in our NGL Logistics segment, and the remaining 20% interest in the Eagle Ford system and the Lucerne 1 and 2 plants are included in our Natural Gas Services segment.

The assets and liabilities of the Lucerne 1 plant are included in the consolidated balance sheets as of December 31, 2014 and December 31, 2013. The following table presents the previously reported December 31, 2013 consolidated balance sheet, condensed and adjusted for the acquisition of the Lucerne 1 plant from DCP Midstream, LLC:

As of December 31, 2013



	DCP Midstream Partners, LP (as previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 Plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	12		$	—	$	12
Accounts receivable	342			—		342
Inventories	67			—		67
Other	82			—		82
Total current assets	503			—		503
Property, plant and equipment, net	3,005			41		3,046
Goodwill and intangible assets, net	283			—		283
Investments in unconsolidated affiliates	627			—		627
Other non-current assets	108			—		108
Total assets	$	4,526		$	41	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	722		$	1	$	723
Long-term debt	1,590			—		1,590
Other long-term liabilities	41			—		41
Total liabilities	2,353			1		2,354
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity	1,956			40		1,996
Accumulated other comprehensive loss	(11		)	—		(11		)
Total partners’ equity	1,945			40		1,985
Noncontrolling interests	228			—		228
Total equity	2,173			40		2,213
Total liabilities and equity	$	4,526		$	41	$	4,567

The results of the Lucerne 1 plant are included in the consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012. The following tables present the previously reported consolidated statements of operations for the years ended December 31, 2013 and 2012, condensed and adjusted for the acquisition of the Lucerne 1 plant from DCP Midstream, LLC:

Year Ended December 31, 2013



	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 Plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	2,695		$	68	$	2,763
Transportation, processing and other	268			3		271
Gains from commodity derivative activity, net	17			—		17
Total operating revenues	2,980			71		3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,381			45		2,426
Operating and maintenance expense	211			4		215
Depreciation and amortization expense	93			2		95
General and administrative expense	62			1		63
Other operating expense	8			—		8
Total operating costs and expenses	2,755			52		2,807
Operating income	225			19		244
Interest expense	(52		)	—		(52		)
Earnings from unconsolidated affiliates	33			—		33
Income before income taxes	206			19		225
Income tax expense	(8		)	—		(8		)
Net income	198			19		217
Net income attributable to noncontrolling interests	(17		)	—		(17		)
Net income attributable to partners	$	181		$	19	$	200

Year Ended December 31, 2012



	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	2,459		$	61	$	2,520
Transportation, processing and other	232			2		234
Losses from commodity derivative activity, net	70			—		70
Total operating revenues	2,761			63		2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,177			38		2,215
Operating and maintenance expense	193			4		197
Depreciation and amortization expense	89			2		91
General and administrative expense	74			1		75
Total operating costs and expenses	2,533			45		2,578
Operating income	228			18		246
Interest expense	(42		)	—		(42		)
Earnings from unconsolidated affiliates	26			—		26
Income before income taxes	212			18		230
Income tax expense	(1		)	—		(1		)
Net income	211			18		229
Net income attributable to noncontrolling interests	(13		)	—		(13		)
Net income attributable to partners	$	198		$	18	$	216

On July 3, 2012, we acquired the Crossroads processing plant and associated gathering system from Penn Virginia Resource Partners, L.P. for $63 million. The acquisition was financed at closing with borrowings under our revolving credit facility. The Crossroads system, located in the southeastern portion of Harrison County in East Texas, includes approximately 8 miles of gas gathering pipeline, an 80 MMcf/d cryogenic processing plant, approximately 20 miles of NGL pipeline and a 50% ownership interest in an approximately 11-mile residue gas pipeline, or CrossPoint Pipeline, LLC, which we accounted for as an unconsolidated affiliate using the equity method. The Crossroads system is a part of our East Texas system, which is included in our Natural Gas Services segment.

We accounted for the Crossroads business combination based on estimates of the fair value of assets acquired and liabilities assumed, including: property, plant and equipment; the equity investment in CrossPoint Pipeline, LLC; a liability for a firm transportation agreement which expires in 2015; and a gas purchase agreement under which a portion of those firm transportation payments are recoverable. Expected cash payments and receipts were recorded at their estimated fair value and are included in other current liabilities, other long-term liabilities, and accounts receivable as of the acquisition date. The following table summarizes the aggregate consideration and fair value of the identifiable assets acquired and liabilities assumed in the acquisition of Crossroads as of the acquisition date:



	July 3, 2012
	(Millions)
Aggregate consideration	$	63

Accounts receivable	$	4
Property, plant and equipment	63
Investments in unconsolidated affiliates	6
Other current liabilities	(4		)
Other long-term liabilities	(6		)
Total	$	63

The results of operations for acquisitions accounted for as a business combination are included in our results subsequent to the date of acquisition. Accordingly, total operating revenues of $22 million and net income of $1 million associated with Crossroads from the acquisition date to December 31, 2012 are included in our consolidated statement of operations for the year ended December 31, 2012.

Supplemental pro forma information is presented for comparative periods prior to the date of acquisition; however, comparative periods in the consolidated financial statements are not adjusted to include the results of the acquisition. The following table presents unaudited supplemental pro forma information for the consolidated statement of operations for the year ended December 31, 2012, as if the acquisition of Crossroads had occurred at the beginning of the year.



	Year Ended December 31, 2012
	DCP Midstream Partners, LP			Acquisition of Crossroads (a)		DCP Midstream Partners, LP Pro Forma
	(Millions)
Total operating revenues	$	2,824		$	27	$	2,851
Net income attributable to partners	$	216		$	2	$	218
Less:
Net income attributable to predecessor operations	(51		)	—		(51		)
General partner’s interest in net income	(41		)	—		(41		)
Net income allocable to limited partners	$	124		$	2	$	126

Net income per limited partner unit - basic and diluted	$	2.28		$	0.03	$	2.31


(a)	The year ended December 31, 2012 includes the financial results of Crossroads for the period from January 1, 2012 through July 2, 2012.

The supplemental pro forma total operating revenues for the year ended December 31, 2012 was adjusted to eliminate $5 million related to a contractual gas processing arrangement between us and Crossroads during the period.

The supplemental pro forma information is not intended to reflect actual results that would have occurred if the acquired business had been combined during the periods presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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+ Details

Agreements and Transactions with Affiliates

12 Months Ended

Dec. 31, 2014

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, which replaced the Omnibus Agreement on February 14, 2013, 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 March 31, 2014, the annual fee payable under the Services Agreement was increased by approximately $15 million, prorated for the remainder of the calendar year, to $44 million. The increase was predominantly attributable to additional general and administrative expenses previously incurred directly by the Eagle Ford system being reallocated to the Services Agreement in connection with the contribution of the remaining 20% interest in the Eagle Ford system to us, bringing our ownership to 100%.

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 our Board of Directors. 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 over the past few years. 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 is 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:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Services/Omnibus Agreement	$	41	$	29	$	26
Other fees — DCP Midstream, LLC	6		17		32
Total — DCP Midstream, LLC	$	47	$	46	$	58

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 $2 million, $2 million and $1 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Lucerne 1 plant incurred $1 million in general and administrative expenses directly from DCP Midstream, LLC for the years ended December 31, 2013 and 2012. The Eagle Ford system incurred $4 million, $14 million and $27 million in general and administrative expenses directly from DCP Midstream, LLC for the years ended December 31, 2014, 2013 and 2012, respectively, before the reallocation of the Eagle Ford system to the Services Agreement on March 31, 2014. For the year ended December 31, 2012, Southeast Texas incurred $3 million in general and administrative expenses directly from DCP Midstream, LLC, before the addition of Southeast Texas to the Omnibus Agreement in March 2012.

Competition

None of DCP Midstream, LLC, or any of its affiliates, including Phillips 66 and Spectra Energy, is restricted, under either the partnership agreement or the Services Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Phillips 66 and Spectra Energy, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Other Agreements and Transactions with DCP Midstream, LLC

DCP Midstream, LLC was a significant customer during the years ended December 31, 2014, 2013 and 2012. We sell a portion of our residue gas, NGLs and condensate to, purchase natural gas and other petroleum products from, and provide gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase from and sell commodities and services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf. We have and may continue to enter into derivative transactions directly with DCP Midstream, LLC, whereby DCP Midstream, LLC is the counterparty.

We have a contractual arrangement with DCP Midstream, LLC, through March 2022, in which we pay DCP Midstream, LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our Natural Gas Services segment. In addition, we have an agreement with DCP Midstream, LLC providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from the Southern Oklahoma system being processed at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates. In addition, as part of this arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates.

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system, included in our Northern Louisiana system, which is part of our Natural Gas Services segment, that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under an interruptible transportation agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand are sold to DCP Midstream, LLC at an index-based price, less contractually agreed upon marketing fees. Revenues associated with these activities are reported gross in our consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

In our Natural Gas Services segment, we sell NGLs processed at certain of our plants, and sell condensate removed from the gas gathering systems that deliver to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for transportation, processing and other charges from the tailgate of the respective asset. In conjunction with our acquisitions of our East Texas and Southeast Texas systems, which are part of our Natural Gas Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on East Texas and Southeast Texas capital projects. These reimbursements are for specific capital projects which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $1 million and $5 million for the years ended December 31, 2013 and 2012 respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of $5 million for the year ended December 31, 2012. We made a distribution to DCP Midstream, LLC related to capital projects at Southeast Texas of $3 million for the year ended December 31, 2013.

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 consolidated statements of operations as transportation, processing and other to affiliates. Under the O'Connor agreement, we received fees of $35 million and $6 million during the years ended December 31, 2014 and 2013, respectively. Under the Lucerne 1 agreement, we received fees of $10 million during the year ended December 31, 2014.

As a result of a downstream outage, certain of our assets were required to curtail NGL production during 2012. DCP Midstream, LLC has reimbursed us for the impact of the curtailment and accordingly, we recorded $3 million to sales of natural gas, propane, NGLs and condensate to affiliates and less than $1 million to transportation, processing and other to affiliates in the consolidated statements of operations for the year ended December 31, 2012.

In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the transportation agreements. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates.

The Wattenberg pipeline has in place a 10-year dedication and transportation agreement with a subsidiary of DCP Midstream, LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are dedicated for transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff. We generally report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates.

In addition to agreements with other third party shippers, the Texas Express, Front Range, Sand Hills and Southern Hills pipelines have in place 15-year transportation agreements, commencing at the pipelines' respective in-service dates, with DCP Midstream, LLC pursuant to which DCP Midstream, LLC has committed to transport minimum throughput volumes at rates defined in each respective pipeline’s tariffs.

We pay a fee to DCP Midstream, LLC to operate our DJ Basin NGL fractionators and receive fees for the processing of DCP Midstream, LLC’s committed NGLs produced by them in Colorado at our DJ Basin NGL fractionators under agreements that are effective through March 2018. We report fees associated with these activities in the consolidated statements of operations as operating and maintenance expense.

Spectra Energy

We had propane supply agreements with Spectra Energy that expired in April 2012, which provided us propane supply at our marine terminals, included in our Wholesale Propane Logistics segment, for up to approximately 185 million gallons of propane annually.

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	2,179	$	1,830	$	1,691
Transportation, processing and other	$	92	$	60	$	52
Purchases of natural gas, propane and NGLs	$	194	$	204	$	173
Gains from commodity derivative activity, net	$	118	$	22	$	53
Operating and maintenance expense	$	1	$	1	$	1
General and administrative expense	$	47	$	46	$	58
Phillips 66:
Sales of natural gas, propane, NGLs and condensate	$	1	$	1	$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—	$	9
Transportation, processing and other	$	—	$	—	$	3
Purchases of natural gas, propane and NGLs	$	—	$	—	$	67
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	77	$	63	$	166
Transportation, processing and other	$	14	$	—	$	—
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	—	$	—	$	2

We had balances with affiliates as follows:



	December 31, 2014		December 31, 2013
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	163	$	211
Accounts payable	$	24	$	37
Unrealized gains on derivative instruments — current	$	207	$	79
Unrealized gains on derivative instruments — long-term	$	25	$	81
Unrealized losses on derivative instruments — current	$	43	$	18
Unrealized losses on derivative instruments — long-term	$	—	$	1
Spectra Energy:
Accounts receivable	$	1	$	1
Accounts payable	$	3	$	6

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References+ Details

Inventories

12 Months Ended

Dec. 31, 2014

Inventory Disclosure [Abstract]

Inventories

Inventories were as follows:



	December 31, 2014		December 31, 2013
	(Millions)
Natural gas	$	36	$	38
NGLs	27		29
Total inventories	$	63	$	67

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 consolidated statements of operations. We recognized $24 million, $4 million and $19 million in lower of cost or market adjustments during the years ended December 31, 2014, 2013 and 2012, respectively.

- Definition

The entire disclosure for inventory. This may include, but is not limited to, the basis of stating inventory, the method of determining inventory cost, the major classes of inventory, and the nature of the cost elements included in inventory. If inventory is stated above cost, accrued net losses on firm purchase commitments for inventory and losses resulting from valuing inventory at the lower-of-cost-or-market may also be included. For LIFO inventory, may disclose the amount and basis for determining the excess of replacement or current cost over stated LIFO value and the effects of a LIFO quantities liquidation that impacts net income.

+ References+ Details

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:



	Depreciable Life	December 31, 2014			December 31, 2013
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,209		$	2,205
Processing, storage, and terminal facilities	35 — 60 Years	2,071			1,645
Other	3 — 30 Years	50			49
Construction work in progress		281			310
Property, plant and equipment		4,611			4,209
Accumulated depreciation		(1,264		)	(1,163		)
Property, plant and equipment, net		$	3,347		$	3,046

Interest capitalized on construction projects for the years ended December 31, 2014, 2013 and 2012 was $8 million, $11 million and $7 million, respectively.

We revised the depreciable lives for our gathering and transmission systems, processing, storage and terminal facilities, and other assets effective April 1, 2012. The key contributing factors to the change in depreciable lives is an increase in the producers' estimated remaining economically recoverable reserves resulting from the widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with better technology used to locate commodity reserves, is giving producers greater access to unconventional commodities. Based on our property, plant and equipment as of April 1, 2012, the new remaining depreciable lives resulted in an approximate $52 million reduction in depreciation expense for the year ended December 31, 2012. This change in our estimated depreciable lives increased net income per limited partner unit by $0.95 for the year ended December 31, 2012.

Depreciation expense was $101 million, $87 million and $83 million for the years ended December 31, 2014, 2013 and 2012, respectively.

During the years ended December 31, 2014 and 2013, we discontinued certain construction projects and wrote off approximately $3 million and $8 million, respectively, in construction work in progress to other expense in the consolidated statements of operations. We had no write-offs during the year ended December 31, 2012.

Asset Retirement Obligations - As of December 31, 2014 and 2013, we had asset retirement obligations of $27 million and $24 million, respectively, included in other long-term liabilities in the consolidated balance sheets. During the year ended December 31, 2014, we recorded a change in estimate to increase our asset retirement obligations by $1 million. The change in estimate was primarily attributable to a reassessment of anticipated timing of settlements and of the original asset retirement obligation amounts. Accretion expense was $2 million and $1 million for the years ended December 31, 2014 and 2013 and accretion benefit was less than $1 million for the year ended December 31, 2012.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

- Definition

The entire disclosure for long-lived, physical assets used in the normal conduct of business and not intended for resale. Includes, but is not limited to, accounting policies and methodology, roll forwards, depreciation, depletion and amortization expense, including composite depreciation, accumulated depreciation, depletion and amortization expense, useful lives and method used, income statement disclosures, assets held for sale and public utility disclosures.

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Goodwill and Intangible assets Goodwill and Intangible assets

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets Disclosure [Text Block]

Goodwill and Intangible Assets

The carrying value of goodwill as of both December 31, 2014 and December 31, 2013 was $154 million, consisting of $82 million for our Natural Gas Services segment, $35 million for our NGL Logistics segment, and $37 million for our Wholesale Propane Logistics segment.

We performed our annual goodwill assessment at the reporting unit level, which is identified by assessing whether any components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the fair value of goodwill exceeded its carrying value and that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment for reporting units due to the potential impact on our operations and cash flows.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:



	December 31,
	2014			2013
	(Millions)
Gross carrying amount	$	164		$	164
Accumulated amortization	(44		)	(35		)
Intangible assets, net	$	120		$	129

We recorded amortization expense of $9 million for the year ended December 31, 2014, and $8 million for each of the years ended December 31, 2013, and 2012. As of December 31, 2014, the remaining amortization periods ranged from approximately 7 years to 21 years, with a weighted-average remaining period of approximately 16 years.

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(Millions)
2015	$	8
2016	8
2017	8
2018	8
2019	8
Thereafter	80
Total	$	120

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

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Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2014

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 Ownership	December 31, 2014		December 31, 2013
		(Millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	413	$	—
Discovery Producer Services LLC	40%	406		348
DCP Southern Hills Pipeline, LLC	33.33%	329		—
Front Range Pipeline LLC	33.33%	169		134
Texas Express Pipeline LLC	10%	98		96
Mont Belvieu Enterprise Fractionator	12.5%	23		26
Mont Belvieu 1 Fractionator	20%	14		16
Other	Various	7		7
Total investments in unconsolidated affiliates		$	1,459	$	627

There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $10 million at December 31, 2014 which is associated with interest capitalized during the construction of the Sand Hills pipeline and is being amortized over the life of the underlying long-lived assets of Sand Hills pipeline.

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $25 million and $28 million at December 31, 2014 and 2013, respectively, which is associated with, and is being amortized over, the life of the underlying long-lived assets of Discovery.

There was an excess of the carrying amount of the investment over the underlying equity of Southern Hills of $8 million at December 31, 2014 which is associated with interest capitalized during the construction of the Southern Hills pipeline and is being amortized over the life of the underlying long-lived assets of Southern Hills pipeline.

There was an excess of the carrying amount of the investment over the underlying equity of Front Range of $5 million and $4 million at December 31, 2014 and 2013, respectively, which is associated with interest capitalized during the construction of the pipeline and is being amortized over the life of the underlying long-lived assets of Front Range pipeline.

There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million at December 31, 2014 and 2013, respectively, which is associated with interest capitalized during the construction of the pipeline and is being amortized over the life of the underlying long-lived assets of Texas Express.

There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu 1 of $4 million and $5 million at December 31, 2014 and 2013, respectively, which is associated with, and is being amortized over the life of the underlying long-lived assets of Mont Belvieu 1.

Earnings (losses) from investments in unconsolidated affiliates were as follows:



	Year Ended December 31,
	2014		2013			2012
	(Millions)
DCP Sand Hills Pipeline, LLC	$	24	$	—		$	—
Mont Belvieu Enterprise Fractionator	16		14			5
DCP Southern Hills Pipeline, LLC	13		—			—
Mont Belvieu 1 Fractionator	12		19			6
Discovery Producer Services LLC	5		1			15
Texas Express Pipeline LLC	3		(1		)	—
Front Range Pipeline LLC	2		—			—
Total earnings from unconsolidated affiliates	$	75	$	33		$	26

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Statements of operations:
Operating revenue	$	826	$	484	$	293
Operating expenses	$	475	$	298	$	190
Net income	$	349	$	186	$	103



	December 31, 2014			December 31, 2013
	(Millions)
Balance sheets:
Current assets	$	207		$	182
Long-term assets	5,157			2,678
Current liabilities	(200		)	(276		)
Long-term liabilities	(164		)	(37		)
Net assets	$	5,000		$	2,547

- Definition

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

+ References+ Details

Fair Value Measurement

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

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 12 - 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. Our swaps are 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 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 December 31, 2014 and December 31, 2013, by consolidated balance sheet caption and by valuation hierarchy, as described above:



	December 31, 2014										December 31, 2013
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	92		$	138	$	230		$	—	$	14		$	65	$	79
Short-term investments (b)	$	24	$	—		$	—	$	24		$	9	$	—		$	—	$	9
Long-term assets (c):
Commodity derivatives	$	—	$	21		$	18	$	39		$	—	$	12		$	75	$	87
Current liabilities (d):
Commodity derivatives	$	—	$	(43	)	$	—	$	(43	)	$	—	$	(26	)	$	—	$	(26	)
Interest rate derivatives	$	—	$	—		$	—	$	—		$	—	$	(2	)	$	—	$	(2	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	—		$	—	$	—		$	—	$	(1	)	$	—	$	(1	)


(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.


(b)	Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.


(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.


(d)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.


(e)	Included in long-term unrealized losses on derivative instruments in our 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 years ended December 31, 2014 and 2013, 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 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 have reflected 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 Assets			Long- Term Assets			Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2014 (a):
Beginning balance	$	65		$	75		$	—		$	—
Net realized and unrealized gains (losses) included in earnings (c)	150			(57		)	—			—
Transfers out of Level 3 (b)	—			—			—			—
Settlements	(77		)	—			—			—
Purchases	—			—			—			—
Ending balance	$	138		$	18		$	—		$	—
Net unrealized gains (losses) on derivatives still held included in earnings (c)	$	138		$	(57	)	$	—		$	—
Year ended December 31, 2013 (a):
Beginning balance	$	40		$	65		$	(1	)	$	—
Net realized and unrealized gains (losses) included in earnings (c)	42			(50		)	—			—
Transfers out of Level 3 (b)	(1		)	(2		)	1			—
Settlements	(40		)	—			—			—
Purchases	24			62			—			—
Ending balance	$	65		$	75		$	—		$	—
Net unrealized gains (losses) on derivatives still held included in earnings (c)	$	41		$	(50	)	$	—		$	—


(a)	There were no issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2014 and 2013.


(b)	Amounts transferred into/out of Level 3 are reflected at fair value as of the end of the period.


(c)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

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.



	December 31, 2014
Product Group	Fair Value		Forward Curve Range
	(Millions)
Assets
NGLs	$	156	$0.17-$1.13	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.

The fair value of our interest rate swaps, if applicable, 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 applicable, 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 over-the-counter, or 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 December 31, 2014 and December 31, 2013, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, were as follows:



		December 31, 2014				December 31, 2013
		Carrying Value		Fair Value		Carrying Value		Fair Value
	(Millions)

Long-Term Senior Notes		$	2,311	$	2,334	$	1,590	$	1,573

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References+ Details

Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt



	December 31, 2014			December 31, 2013
	(Millions)
Commercial Paper
Short-term borrowings, weighted-average interest rate of 1.14% as of December 31, 2013	$	—		$	335
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			—
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			—
Unamortized discount	(14		)	(10		)
Total debt	2,311			1,925
Short-term borrowings	—			(335		)
Current maturities of long-term debt	(250		)	—
Total long-term debt	$	2,061		$	1,590

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 replaced our previous Credit Agreement dated as of November 10, 2011, which had a total borrowing capacity of $1 billion and would have matured on November 10, 2016. The Amended and Restated Credit Agreement will be used for working capital requirements and other general partnership purposes including acquisitions.

Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.275% 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 0.275% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.225% 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 December 31, 2014, the unused capacity under the Amended and Restated Credit Agreement was $1,249 million, which is net of letters of credit. Our borrowing capacity may be limited by the Amended and Restated Credit Agreement’s financial covenant requirements. 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. Further, our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings based pricing grid. Subsequent to December 31, 2014, our credit rating has been lowered below investment grade. As a result of this ratings action, interest rates and fees under the DCP Partners Amended and Restated Credit Agreement have increased.

Commercial Paper Program

We have a commercial paper program, or the Commercial Paper Program, under which we may issue unsecured commercial paper notes. Amounts available under this program may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of notes outstanding, combined with the amount outstanding under our Amended and Restated Credit Agreement, not to exceed $1.25 billion in the aggregate. As of December 31, 2014, we had no commercial paper outstanding. Subsequent to December 31, 2014, our credit rating has been lowered below investment grade. As a result of this ratings action, we longer have access to the Commercial Paper Program. Our available liquidity under the Commercial Paper Program will be replaced with borrowings under the DCP Partners 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 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.

In March 2013, we issued $500 million of 3.875% 10-year Senior Notes due March 15, 2023. We received proceeds of $490 million, net of underwriters’ fees, related expenses and unamortized discounts, which we used to fund a portion of the purchase price for the acquisition of an additional 46.67% interest in the Eagle Ford system. Interest on the notes is paid semi-annually on March 15 and September 15 of each year, commencing September 15, 2013. The notes will mature on March 15, 2023, 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 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)
2015	$	250
2016	—
2017	500
2018	—
2019	325
Thereafter	1,250
	2,325
Unamortized discount	(14		)
Total	$	2,311

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References+ Details

Risk Management and Hedging Activities

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, or 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. 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 2014 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 consolidated statements of operations as a gain or a loss on commodity derivative activity.

Our Wholesale Propane Logistics segment is generally designed 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 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 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.

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 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 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 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 December 31, 2014.

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 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 $4 million as of December 31, 2014.

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.


•	In the event that we were to be downgraded below investment grade by at least one of the major credit rating agencies, 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.

•

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 December 31, 2014, 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 December 31, 2014, all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts 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 December 31, 2014, if a credit-risk related event were to occur, we would not have been 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 at that time.

Unconsolidated Affiliates

Discovery, one of our unconsolidated affiliates, entered into agreements with a pipe vendor denominated in a foreign currency in connection with the expansion of the natural gas gathering pipeline system in the deepwater Gulf of Mexico, the Keathley Canyon Connector. Discovery entered into certain foreign currency derivative contracts to mitigate a portion of the foreign currency exchange risks which were designated as cash flow hedges. As these hedges are owned by Discovery, an unconsolidated affiliate, and designated as cash flow hedges, we include the impact to AOCI on our consolidated balance sheet.

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 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:



	December 31, 2014									December 31, 2013
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	269		$	(42	)	$	227		$	166		$	(13	)	$	153
Liabilities:
Commodity derivatives	$	(43	)	$	42		$	(1	)	$	(27	)	$	13		$	(14	)
Interest rate derivatives	$	—		$	—		$	—		$	(2	)	$	—		$	(2	)


(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 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 December 31, 2014 and 2013.



Balance Sheet Line Item	December 31, 2014		December 31, 2013		Balance Sheet Line Item	December 31, 2014			December 31, 2013
	(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	$	230	$	79	Unrealized losses on derivative instruments — current	$	(43	)	$	(26	)
Unrealized gains on derivative instruments — long-term	39		87		Unrealized losses on derivative instruments — long-term	—			(1		)
	$	269	$	166		$	(43	)	$	(27	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments — current	$	—	$	—	Unrealized losses on derivative instruments — current	$	—		$	(2	)
Unrealized gains on derivative instruments — long-term	—		—		Unrealized losses on derivative instruments — long-term	—			—
	$	—	$	—		$	—		$	(2	)

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 year ended December 31, 2014:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(6	)		$	(6	)	$	1	$	(11	)
Losses reclassified from AOCI to earnings — effective portion	2			(b) (c)	—			—		2
Net deferred (losses) gains in AOCI (ending balance)	$	(4	)		$	(6	)	$	1	$	(9	)
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 consolidated statements of operations.


(c)	For the year ended December 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.

For the year ended December 31, 2014, no derivative losses attributable to the ineffective portion and amount excluded from effectiveness testing was recognized in gains or losses from commodity derivative activity, net and interest expense in our 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 year ended December 31, 2013:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(10	)		$	(6	)	$	1	$	(15	)
Losses reclassified from AOCI to earnings — effective portion	$	4		(b)	$	—		$	—	$	4
Net deferred losses in AOCI (ending balance)	$	(6	)		$	(6	)	$	1	$	(11	)


(a)	Relates to Discovery, our unconsolidated affiliate.


(b)	Included in interest expense in our consolidated statements of operations.

For the year ended December 31, 2013, less than $1 million of derivative losses attributable to the ineffective portion was recognized in gains or losses from commodity derivative activity, net and interest expense in our consolidated statements of operations. For the year ended December 31, 2013, $1 million of derivative gains or losses were reclassified from AOCI to current period earnings as a result of amounts excluded from effectiveness testing or 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 consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:



Commodity Derivatives: Statements of Operations Line Item	Year Ended December 31,
	2014			2013			2012
	(Millions)
Third party:
Realized (losses) gains	$	(2	)	$	(19	)	$	4
Unrealized gains	38			14			13
Gains (losses) from commodity derivative activity, net	$	36		$	(5	)	$	17
Affiliates:
Realized gains	$	70		$	73		$	45
Unrealized gains (losses)	48			(51		)	8
Gains from commodity derivative activity, net —affiliates	$	118		$	22		$	53

Interest Rate Derivatives: Statements of Operations Line Item	Year Ended December 31,
	2014			2013			2012
	(Millions)
Third party:
Realized losses	$	(2	)	$	(2	)	$	(7	)
Unrealized gains	2			2			7
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.



	December 31, 2014
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)		Net (Short) Position (MMBtu)		Net (Short) Position (Bbls)		Net Long Position (MMBtu)
2015	(745,695	)	(20,803,975	)	(5,573,570	)	2,640,000
2016	(561,922	)	(5,668,564	)	(813,267	)	1,690,000
2017	—		(6,387,500	)	—		—

	December 31, 2013
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)		Net (Short) Position (MMBtu)		Net (Short) Position (Bbls)		Net Long Position (MMBtu)
2014	(690,945	)	(21,673,620	)	(5,171,910	)	21,415,000
2015	(745,695	)	(9,458,975	)	(5,691,570	)	1,875,000
2016	(561,922	)	(1,838,564	)	(813,267	)	—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of December 31, 2013, we had swaps with a notional value of $70 million and $80 million, which, in aggregate, exchanged $150 million of our floating rate obligation to a fixed rate obligation through June 2014.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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+ Details

Partnership Equity and Distributions

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Partnership Equity and Distributions

In June 2014, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $500 million, which became effective on July 11, 2014. The shelf registration statement allows us to issue additional common units. In September 2014, we entered into an equity distribution agreement, or the 2014 equity distribution agreement, with a group of financial institutions as sales agents. The 2014 equity distribution agreement provides for the offer and sale from time to time, through our sales agents, of common units having an aggregate offering amount of up to $500 million. During the year ended December 31, 2014, we issued 2,256,066 of our common units pursuant to the 2014 equity distribution agreement and received proceeds of $119 million, net of commissions and accrued offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes. As of December 31, 2014, approximately $380 million remained available for sale pursuant to the 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.

In August 2013, we issued 9,000,000 common units to the public at $50.04 per unit. We received proceeds of $434 million, net of offering costs.

In June 2013, we filed a shelf registration statement on Form S-3, or the June 2013 shelf registration statement, with the SEC with a maximum offering price of $300 million, which became effective on June 27, 2013. The June 2013 shelf registration statement allowed us to issue additional common units. In November 2013, we entered into an equity distribution agreement related to the June 2013 shelf registration statement, or the 2013 equity distribution agreement, with a group of financial institutions as sales agents. The 2013 equity distribution agreement provided for the offer and sale from time to time, through our sales agents, of common units having an aggregate offering amount of up to $300 million. During the year ended December 31, 2014, we issued 3,769,635 common units pursuant to the 2013 equity distribution agreement and received proceeds of $206 million, which is net of commissions and offering costs of $2 million. During the year ended December 31, 2013, we issued 1,839,430 of our common units pursuant to the 2013 equity distribution agreement and received proceeds of $87 million, net of commissions and offering costs of $1 million. The proceeds were used to finance growth opportunities and for general partnership purposes. In connection with our entry into the 2014 equity distribution agreement, we terminated the 2013 equity distribution agreement in September 2014. In October 2014, we de-registered the common units that remained unsold under the 2013 equity distribution agreement at the time of its termination.

In March 2013, we issued 2,789,739 common units to DCP Midstream, LLC as partial consideration for 46.67% interest in the Eagle Ford system.

In March 2013, we issued 12,650,000 common units to the public at $40.63 per unit. We received proceeds of $494 million, net of offering costs.

In November 2012, we issued 1,912,663 common units to DCP Midstream, LLC as partial consideration for our 33.33% interest in the Eagle Ford system.

In July 2012, we issued 1,536,098 common units to DCP Midstream, LLC as partial consideration for the Mont Belvieu fractionators.

In July 2012, we closed a private placement of equity with a group of institutional investors in which we sold 4,989,802 common units at a price of $35.55 per unit, and received proceeds of $174 million, net of offering costs.

In June 2012, we filed a universal shelf registration statement on Form S-3 with the SEC with an unlimited offering amount, to replace an existing shelf registration statement. The universal shelf registration statement allows us to issue additional common units and debt securities. Our 9,000,000 and 12,650,000 common units issued in August 2013 and March 2013, respectively, and 2.50% 5-year Senior Notes were issued under this registration statement.

In March 2012, we issued 5,148,500 common units at $47.42 per unit. We received proceeds of $234 million, net of offering costs.

In March 2012, we issued 1,000,417 common units to DCP Midstream, LLC as partial consideration for the remaining 66.67% interest in Southeast Texas.

In February 2012, we issued 30,701 common units under our 2005 Long-Term Incentive Plan, or 2005 LTIP, to employees as compensation for their service.

In January 2012, we issued 727,520 common units to DCP Midstream, LLC as partial consideration for the remaining 49.9% interest in East Texas.

In August 2011, we entered into an equity distribution agreement with a financial institution, as sales agent. The agreement provides for the offer and sale from time to time, through our sales agent, of common units having an aggregate offering amount of up to $150 million. During the year ended December 31, 2013, we issued 1,408,547 of our common units pursuant to this equity distribution agreement and received proceeds of $67 million, net of commissions and offering costs of $2 million. During the year ended December 31, 2012, we issued 1,147,654 of our common units pursuant to this equity distribution agreement and received proceeds of $47 million, net of commissions and offering costs of $2 million. The proceeds were used to finance growth opportunities and for general partnership purposes. In September 2013, we de-registered the common units that remained unsold under this equity distribution agreement.

Definition of Available Cash — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined in the partnership agreement, to unitholders of record on the applicable record date, as determined by our general partner. Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:


•	less the amount of cash reserves established by the general partner to:

•provide for the proper conduct of our business;

•comply with applicable law, any of our debt instruments or other agreements; and


•	provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;


•	plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 0.3% and limited partner interest of approximately 1.7% as of December 31, 2014. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Distributions of Available Cash - Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter in the following manner:


•	first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;


•	second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;


•	third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and


•	thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2014, 2013 and 2012:



Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86
November 14, 2013	$	0.7200	$	82
August 14, 2013	$	0.7100	$	72
May 15, 2013	$	0.7000	$	69
February 14, 2013	$	0.6900	$	54
November 14, 2012	$	0.6800	$	53
August 14, 2012	$	0.6700	$	49
May 15, 2012	$	0.6600	$	43
February 14, 2012	$	0.6500	$	37

- Definition

The entire disclosure for the formation, structure, control and ownership of the partnership. Disclosures related to accounts comprising partners' capital. Includes balances of general partners' capital account, limited partners' capital account, preferred partners' capital account and total partners' capital account and units outstanding; accumulated other comprehensive income; amount and nature of changes to amount of partner's capital and units outstanding by class, rights and privileges for each class of units; distribution policies and distributions paid by unit class; impact of and correction of an error in previously issued financial statements; limitations of partners' liability; redemption, conversion and distribution policies; and deferred compensation related to the issuance of units.

+ References+ Details

Equity-Based Compensation (Notes)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Equity-Based Compensation

On November 28, 2005, the board of directors of our General Partner adopted a Long-Term Incentive Plan, or the 2005 LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2005 LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. The 2005 LTIP phantom units consist of a notional unit based on the value of the Partnership's common units. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be issued and delivered pursuant to awards under the 2005 LTIP. Awards that are canceled or forfeited, or are withheld to satisfy the General Partner’s tax withholding obligations, are available for delivery pursuant to other awards. On February 15, 2012, the board of directors of our General Partner adopted a 2012 LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provides for the grant of phantom units and DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Spectra Energy. The LTIPs were administered by the compensation committee of the General Partner’s board of directors through 2012, and by the General Partner’s board of directors beginning in 2013. Awards are issued under both LTIPs and all awards are subject to cliff vesting.

Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units at the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date.

We recognized $1 million in compensation expense related to our LTIP awards for the year ended December 31, 2014 and $2 million for each of the years ended December 31, 2013 and 2012. As of December 31, 2014, we have less than $1 million of unrecognized compensation expense related to LTIP awards.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References+ Details

Net Income or Loss per Limited Partner Unit	12 Months Ended
Net Income or Loss per Limited Partner Unit	Dec. 31, 2014
Earnings Per Share [Abstract]
Net Income or Loss per Limited Partner Unit	Net Income or Loss per Limited Partner Unit Our net income or loss is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership agreement. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU. 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 the LTIP. The dilutive effect of unit-based awards was 10,574, 19,179 and 33,034 equivalent units during the years ended December 31, 2014, 2013 and 2012, respectively.

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

We are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for federal income tax purposes. Accordingly, we had no federal income tax expense for the years ended December 31, 2014, 2013 and 2012.

The State of Texas imposes a margin tax that is assessed at 0.95%, 0.975%, and 1% of taxable margin apportioned to Texas for the years ended December 31, 2014, 2013 and 2012.

Income tax expense consists of the following:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Current state income tax expense	$	3	$	3	$	1
Deferred state income tax expense	3		5		—
Total income tax expense	$	6	$	8	$	1

We had net long-term deferred tax liabilities of $13 million and $11 million as of December 31, 2014 and 2013, included in other long-term liabilities on the consolidated balance sheets. These state deferred tax liabilities relate to our Texas operations and are primarily associated with depreciation related to property, plant and equipment.

Our effective tax rate differs from statutory rates, primarily due to being structured as a master limited partnership, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References+ Details

Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

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.

Insurance - We renewed our insurance policies in May, June, July and August 2014 for the 2014-2015 insurance year. We contract with third party insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay. We are jointly insured with DCP Midstream, LLC for a portion of the insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies that are of similar size to us and with similar types of operations.

The insurance on Discovery, as placed by Williams Field Service Group LLC, for the 2014-2015 insurance year includes general and excess liability, onshore property damage, including named windstorm and business interruption, and offshore non-wind property and business interruption insurance. The availability of offshore named windstorm property and business interruption insurance has been significantly reduced over the past few years, we believe as a result of higher industry-wide damage claims. Additionally, we believe the named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, high deductibles and low coverage limits. As such, Discovery continues to elect not to purchase offshore named windstorm property and business interruption insurance coverage for the 2014-2015 insurance year.

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 consolidated results of operations, financial position or cash flows.

Indemnification - DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors.

Other Commitments and Contingencies - We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, totaled $13 million, $17 million, and $14 million for the years ended December 31, 2014, 2013, and 2012, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2014:



	(Millions)
2015	$	15
2016	12
2017	11
2018	9
2019	8
Thereafter	26
Total minimum rental payments	$	81

- Definition

The entire disclosure for commitments and contingencies.

+ References+ Details

Business Segments

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

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, the Southern Hills intrastate pipeline, the Sand Hills interstate pipeline, the Black Lake and Wattenberg interstate pipelines, the Seabreeze and Wilbreeze intrastate pipelines, 33.33% interest in the Front Range interstate pipeline, and 10% interest in the Texas Express intrastate pipeline.

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 owned rail terminals, one owned marine terminal, one leased 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:

Year Ended December 31, 2014:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	3,163		$	73		$	406		$	—		$	3,642
Gross margin (a)	$	756		$	73		$	18		—			$	847
Operating and maintenance expense	(189		)	(16		)	(11		)	—			(216		)
Depreciation and amortization expense	(101		)	(7		)	(2		)	—			(110		)
General and administrative expense	—			—			—			(64		)	(64		)
Other expense	(2		)	(1		)	—			—			(3		)
Earnings from unconsolidated affiliates	5			70			—			—			75
Interest expense	—			—			—			(86		)	(86		)
Income tax expense	—			—			—			(6		)	(6		)
Net income (loss)	$	469		$	119		$	5		$	(156	)	$	437
Net income attributable to noncontrolling interests	(14		)	—			—			—			(14		)
Net income (loss) attributable to partners	$	455		$	119		$	5		$	(156	)	$	423
Non-cash derivative mark-to-market (b)	$	89		$	—		$	(3	)	$	—		$	86
Non-cash lower of cost or market adjustments	$	11		$	—		$	13		$	—		$	24
Capital expenditures	$	297		$	25		$	16		$	—		$	338
Acquisition expenditures	$	102		$	673		$	—		$	—		$	775
Investments in unconsolidated affiliates	$	75		$	76		$	—		$	—		$	151

Year Ended December 31, 2013:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,598		$	73		$	380		$	—		$	3,051
Gross margin (a)	$	501		$	72		$	52		$	—		$	625
Operating and maintenance expense	(184		)	(16		)	(15		)	—			(215		)
Depreciation and amortization expense	(87		)	(6		)	(2		)	—			(95		)
General and administrative expense	—			—			—			(63		)	(63		)
Other expense	(1		)	(3		)	(4		)	—			(8		)
Earnings from unconsolidated affiliates	1			32			—			—			33
Interest expense	—			—			—			(52		)	(52		)
Income tax expense	—			—			—			(8		)	(8		)
Net income (loss)	$	230		$	79		$	31		$	(123	)	$	217
Net income attributable to noncontrolling interests	(17		)	—			—			—			(17		)
Net income (loss) attributable to partners	$	213		$	79		$	31		$	(123	)	$	200
Non-cash derivative mark-to-market (b)	$	(36	)	$	—		$	(1	)	$	1		$	(36	)
Non-cash lower of cost or market adjustments	$	2		$	—		$	2		$	—		$	4
Capital expenditures	$	334		$	24		$	5		$	—		$	363
Acquisition expenditures	$	696		$	86		$	—		$	—		$	782
Investments in unconsolidated affiliates	$	133		$	109		$	—		$	—		$	242

Year Ended December 31, 2012:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,345		$	64		$	415		$	—		$	2,824
Gross margin (a)	$	503		$	64		$	42		$	—		$	609
Operating and maintenance expense	(166		)	(16		)	(15		)	—			(197		)
Depreciation and amortization expense	(83		)	(6		)	(2		)	—			(91		)
General and administrative expense	—			—			—			(75		)	(75		)
Earnings from unconsolidated affiliates	15			11			—			—			26
Interest expense	—			—			—			(42		)	(42		)
Income tax expense	—			—			—			(1		)	(1		)
Net income (loss)	$	269		$	53		$	25		$	(118	)	$	229
Net income attributable to noncontrolling interests	(13		)	—			—			—			(13		)
Net income (loss) attributable to partners	$	256		$	53		$	25		$	(118	)	$	216
Non-cash derivative mark-to-market (b)	$	20		$	—		$	1		$	—		$	21
Capital expenditures	$	468		$	12		$	4		$	—		$	484
Acquisitions net of cash acquired	$	715		$	30		$	—		$	—		$	745
Investments in unconsolidated affiliates	$	115		$	43		$	—		$	—		$	158



	December 31,		December 31,
	2014		2013
	(Millions)
Segment long-term assets:
Natural Gas Services (c)	$	3,609	$	3,303
NGL Logistics	1,364		555
Wholesale Propane Logistics	118		106
Other (d)	58		100
Total long-term assets	5,149		4,064
Current assets (c)	590		503
Total assets	$	5,739	$	4,567

(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 derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.

(c)

The segment information as of and for the years ended December 31, 2014, 2013 and 2012 includes the results of our Lucerne 1 plant, an 80% interest in the Eagle Ford system and a 100% interest in Southeast Texas. These transfers of net assets between entities under common control were 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.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef

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-Name Accounting Standards Codification

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+ Details

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	73	$	40	$	23
Cash paid for income taxes, net of income tax refunds	$	2	$	1	$	1
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	43	$	27	$	47
Other non-cash additions of property, plant and equipment	$	4	$	1	$	8
Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions	$	65	$	—	$	—
Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$	160	$	125	$	—
Accounts payable related to equity issuance costs	$	—	$	1	$	—
Non-cash change in parent advances	$	—	$	—	$	(115	)

Quarterly Financial Data (Notes)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2014 and 2013 were as follows (millions, except per unit amounts):



2014	First (a)			Second		Third		Fourth			Year Ended December 31, 2014 (a)
Total operating revenues	$	1,081		$	812	$	868	$	881		$	3,642
Operating income	$	108		$	37	$	111	$	198		$	454
Net income	$	89		$	29	$	116	$	203		$	437
Net income attributable to noncontrolling interests	$	(10	)	$	—	$	—	$	(4	)	$	(14	)
Net income attributable to partners	$	79		$	29	$	116	$	199		$	423
Net income allocable to limited partners	$	47		$	2	$	86	$	168		$	303
Basic and diluted net income per limited partner unit	$	0.50		$	0.02	$	0.77	$	1.48		$	2.84



2013	First (a)(b)			Second (a)			Third (a)			Fourth (a)		Year Ended December 31, 2013 (a)
Total operating revenues	$	749		$	792		$	689		821		3,051
Operating income	$	65		$	117		$	14		48		244
Net income	$	60		$	111		$	6		40		217
Net income attributable to noncontrolling interests	$	(3	)	$	(4	)	$	(3	)	(7	)	(17	)
Net income attributable to partners	$	57		$	107		$	3		33		200
Net income (loss) allocable to limited partners	$	31		$	86		$	(20	)	8		105
Basic and diluted net income (loss) per limited partner unit	$	0.48		$	1.11		$	(0.24	)	0.09		1.34

(a)Our consolidated results of operations have been adjusted to retrospectively include the historical results of the Lucerne 1 plant for the periods presented.

(b)Our consolidated results of operations have been adjusted to retrospectively include the historical results of an 80% interest in the Eagle Ford system for the periods presented.

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References+ Details

Supplementary Information - Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2014

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. In conjunction with the universal shelf registration statement on Form S-3 which became effective on June 14, 2012, 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
	December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(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 Balance Sheet
	December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	12		$	—		$	12
Accounts receivable, net	—		—			342			—			342
Inventories	—		—			67			—			67
Other	—		—			82			—			82
Total current assets	—		—			503			—			503
Property, plant and equipment, net	—		—			3,046			—			3,046
Goodwill and intangible assets, net	—		—			283			—			283
Advances receivable — consolidated subsidiaries	1,805		1,683			—			(3,488		)	—
Investments in consolidated subsidiaries	181		426			—			(607		)	—
Investments in unconsolidated affiliates	—		—			627			—			627
Other long-term assets	—		12			96			—			108
Total assets	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	1	$	350		$	372		$	—		$	723
Advances payable — consolidated subsidiaries	—		—			3,488			(3,488		)	—
Long-term debt	—		1,590			—			—			1,590
Other long-term liabilities	—		—			41			—			41
Total liabilities	1		1,940			3,901			(3,488		)	2,354
Commitments and contingent liabilities
Equity:
Partners’ equity:
Predecessor equity	—		—			40			—			40
Net equity	1,985		187			391			(607		)	1,956
Accumulated other comprehensive loss	—		(6		)	(5		)	—			(11		)
Total partners’ equity	1,985		181			426			(607		)	1,985
Noncontrolling interests	—		—			228			—			228
Total equity	1,985		181			654			(607		)	2,213
Total liabilities and equity	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567


(a)	The financial information as of December 31, 2013 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	3,143		$	—		$	3,143
Transportation, processing and other	—		—			345			—			345
Gains from commodity derivative activity, net	—		—			154			—			154
Total operating revenues	—		—			3,642			—			3,642
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,795			—			2,795
Operating and maintenance expense	—		—			216			—			216
Depreciation and amortization expense	—		—			110			—			110
General and administrative expense	—		—			64			—			64
Other expense	—		—			3			—			3
Total operating costs and expenses	—		—			3,188			—			3,188
Operating income	—		—			454			—			454
Interest expense, net	—		(86		)	—			—			(86		)
Income from consolidated subsidiaries	423		509			—			(932		)	—
Earnings from unconsolidated affiliates	—		—			75			—			75
Income before income taxes	423		423			529			(932		)	443
Income tax expense	—		—			(6		)	—			(6		)
Net income	423		423			523			(932		)	437
Net income attributable to noncontrolling interests	—		—			(14		)	—			(14		)
Net income attributable to partners	$	423	$	423		$	509		$	(932	)	$	423


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	423	$	423	$	523		$	(932	)	$	437
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	425		425		523			(934		)	439
Total comprehensive income attributable to noncontrolling interests	—		—		(14		)	—			(14		)
Total comprehensive income attributable to partners	$	425	$	425	$	509		$	(934	)	$	425


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,763		$	—		$	2,763
Transportation, processing and other	—		—			271			—			271
Gains from commodity derivative activity, net	—		—			17			—			17
Total operating revenues	—		—			3,051			—			3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,426			—			2,426
Operating and maintenance expense	—		—			215			—			215
Depreciation and amortization expense	—		—			95			—			95
General and administrative expense	—		—			63			—			63
Other expense	—		—			8			—			8
Total operating costs and expenses	—		—			2,807			—			2,807
Operating income	—		—			244			—			244
Interest expense	—		(52		)	—			—			(52		)
Earnings from unconsolidated affiliates	—		—			33			—			33
Income from consolidated subsidiaries	200		252			—			(452		)	—
Income before income taxes	200		200			277			(452		)	225
Income tax expense	—		—			(8		)	—			(8		)
Net income	200		200			269			(452		)	217
Net income attributable to noncontrolling interests	—		—			(17		)	—			(17		)
Net income attributable to partners	$	200	$	200		$	252		$	(452	)	$	200

(a)

The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant and an 80% interest in the Eagle Ford system. These transfers of net assets between entities under common control were 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.



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	200	$	200	$	269		$	(452	)	$	217
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		4		—			—			4
Other comprehensive income from consolidated subsidiaries	4		—		—			(4		)	—
Total other comprehensive income	4		4		—			(4		)	4
Total comprehensive income	204		204		269			(456		)	221
Total comprehensive income attributable to noncontrolling interests	—		—		(17		)	—			(17		)
Total comprehensive income attributable to partners	$	204	$	204	$	252		$	(456	)	$	204

(a)



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,520		$	—		$	2,520
Transportation, processing and other	—		—			234			—			234
Gains from commodity derivative activity, net	—		—			70			—			70
Total operating revenues	—		—			2,824			—			2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,215			—			2,215
Operating and maintenance expense	—		—			197			—			197
Depreciation and amortization expense	—		—			91			—			91
General and administrative expense	—		—			75			—			75
Total operating costs and expenses	—		—			2,578			—			2,578
Operating income	—		—			246			—			246
Interest expense	—		(41		)	(1		)	—			(42		)
Earnings from unconsolidated affiliates	—		—			26			—			26
Income from consolidated subsidiaries	216		257			—			(473		)	—
Income before income taxes	216		216			271			(473		)	230
Income tax expense	—		—			(1		)	—			(1		)
Net income	216		216			270			(473		)	229
Net income attributable to noncontrolling interests	—		—			(13		)	—			(13		)
Net income attributable to partners	$	216	$	216		$	257		$	(473	)	$	216

(a)

The financial information for the year ended December 31, 2012 includes the results of our Lucerne 1 plant, an 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries				Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	216	$	216		$	270			$	(473	)	$	229
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	—		10			—				—			10
Net unrealized losses on cash flow hedges	—		(1		)	—				—			(1		)
Other comprehensive income from consolidated subsidiaries	9		—			—				(9		)	—
Total other comprehensive income	9		9			—			—	(9		)	9
Total comprehensive income	225		225			270				(482		)	238
Total comprehensive income attributable to noncontrolling interests	—		—			(13		)		—			(13		)
Total comprehensive income attributable to partners	$	225	$	225		$	257			$	(482	)	$	225

(a)



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	—		(73	)	597		—		524
INVESTING ACTIVITIES:
Intercompany transfers	(581	)	(280	)	—		861		—
Capital expenditures	—		—		(338	)	—		(338	)
Acquisitions, net of cash acquired	—		—		(102	)	—		(102	)
Acquisition of unconsolidated affiliates	—		—		(673	)	—		(673	)
Investments in unconsolidated affiliates	—		—		(151	)	—		(151	)
Proceeds from sales of assets	—		—		28		—		28
Net cash used in investing activities	(581	)	(280	)	(1,236	)	861		(1,236	)
FINANCING ACTIVITIES:
Intercompany transfers	—		—		861		(861	)	—
Proceeds from long-term debt	—		719		—		—		719
Payments of commercial paper, net	—		(335	)	—		—		(335	)
Payments of deferred financing costs	—		(7	)	—		—		(7	)
Excess purchase price over acquired interests and commodity hedges	—		—		(18	)	—		(18	)
Proceeds from issuance of common units, net of offering costs	1,001		—		—		—		1,001
Net change in advances to predecessor from DCP Midstream, LLC	—		—		(6	)	—		(6	)
Distributions to limited partners and general partner	(420	)	—		—		—		(420	)
Distributions to noncontrolling interests	—		—		(14	)	—		(14	)
Purchase of additional interest in a subsidiary	—		—		(198	)	—		(198	)
Contributions from noncontrolling interests	—		—		3		—		3
Net cash provided by financing activities	581		377		628		(861	)	725
Net change in cash and cash equivalents	—		24		(11	)	—		13
Cash and cash equivalents, beginning of period	—		—		12		—		12
Cash and cash equivalents, end of period	—		24		1		—		25


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2013 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(45	)	$	387		$	3		$	345
INVESTING ACTIVITIES:
Intercompany transfers	(806		)	(258		)	—			1,064			—
Capital expenditures	—			—			(363		)	—			(363		)
Acquisitions, net of cash acquired	—			—			(696		)	—			(696		)
Investments in unconsolidated affiliates	—			—			(242		)	—			(242		)
Acquisition of unconsolidated affiliates	—			—			(86		)	—			(86		)
Net cash used in investing activities	(806		)	(258		)	(1,387		)	1,064			(1,387		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,064			(1,064		)	—
Proceeds from long-term debt	—			1,957			—			—			1,957
Payments of long-term debt	—			(1,988		)	—			—			(1,988		)
Proceeds from issuance of commercial paper	—			335			—			—			335
Payment of deferred financing costs	—			(4		)	—			—			(4		)
Proceeds from issuance of common units, net of offering costs	1,083			—			—			—			1,083
Excess purchase price over acquired interests and commodity hedges	—			—			(85		)	—			(85		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			11			—			11
Distributions to limited partners and general partner	(277		)	—			—			—			(277		)
Distributions to noncontrolling interests	—			—			(24		)	—			(24		)
Contributions from noncontrolling interests	—			—			46			—			46
Distributions to DCP Midstream, LLC	—			—			(3		)	—			(3		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash provided by financing activities	806			300			1,010			(1,064		)	1,052
Net change in cash and cash equivalents	—			(3		)	10			3			10
Cash and cash equivalents, beginning of period	—			3			2			(3		)	2
Cash and cash equivalents, end of period	$	—		$	—		$	12		$	—		$	12

(a)

The financial information during the year ended December 31, 2013 includes the results of our Lucerne 1 plant and an 80% interest in the Eagle Ford system. These transfers of net assets between entities under common control were 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.



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2012 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(39	)	$	142		$	(1	)	$	102
INVESTING ACTIVITIES:
Intercompany transfers	(274		)	(827		)	—			1,101			—
Capital expenditures	—			—			(484		)	—			(484		)
Acquisitions, net of cash acquired	—			—			(745		)	—			(745		)
Investments in unconsolidated affiliates	—			—			(158		)	—			(158		)
Return of investment from unconsolidated affiliate	—			—			1			—			1
Proceeds from sale of assets	—			—			2			—			2
Net cash used in investing activities	(274		)	(827		)	(1,384		)	1,101			(1,384		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,101			(1,101		)	—
Proceeds from long-term debt	—			2,665			—			—			2,665
Payments of long-term debt	—			(1,792		)	—			—			(1,792		)
Payment of deferred financing costs	—			(8		)	—			—			(8		)
Proceeds from issuance of common units, net of offering costs	455			—			—			—			455
Excess purchase price over acquired assets	—			—			(225		)	—			(225		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			336			—			336
Distributions to common unitholders and general partner	(181		)	—			—			—			(181		)
Distributions to noncontrolling interests	—			—			(9		)	—			(9		)
Contributions from noncontrolling interests	—			—			25			—			25
Contributions from DCP Midstream, LLC	—			—			10			—			10
Net cash provided by financing activities	274			865			1,238			(1,101		)	1,276
Net change in cash and cash equivalents	—			(1		)	(4		)	(1		)	(6		)
Cash and cash equivalents, beginning of year	—			4			6			(2		)	8
Cash and cash equivalents, end of year	$	—		$	3		$	2		$	(3	)	$	2

(a)

The financial information during the year ended December 31, 2012 includes the results of our Lucerne 1 plant, our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

Valuation and Qualifying Accounts and Reserves Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2014, 2013, and 2012 are as follows:



	Balance at Beginning of Period		Charged to Consolidated Statements of Operations		Charged to Other Accounts		Deductions/Other			Balance at End of Period
	(Millions)
December 31, 2014
Environmental	$	2	$	1	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	3	$	1	$	—	$	(1	)	$	3
December 31, 2013
Environmental	$	2	$	1	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	3	$	1	$	—	$	(1	)	$	3
December 31, 2012
Environmental	$	3	$	—	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	4	$	—	$	—	$	(1	)	$	3


(a)	Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in other long-term assets, and other contingency liabilities, which are included in other current liabilities.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 29, 2015, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on February 13, 2015 to unitholders of record on February 9, 2015. In January 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. 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. Originating near Carthage, Texas, the 10-inch diameter expansion will extend approximately 60 miles to Lufkin, Texas and will have an initial capacity of approximately 50 MBbls/d, with expansion to 100 MBbls/d possible following installation of additional pump stations. 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 and operate the expansion, which is expected to be in service in the first quarter of 2016. On February 10, 2015, we, along with Williams Partners L.P., announced that the new extended Discovery natural gas gathering pipeline system is now flowing natural gas. The Keathley Canyon Connector, a 20-inch diameter, 209-mile subsea natural gas gathering pipeline is capable of gathering more than 400 MMcf/d of natural gas, and originates in the southeast portion of the Keathley Canyon protraction area of the Gulf of Mexico, and terminates into Discovery’s 30-inch diameter mainline near South Timbalier Block 283. Subsequent to December 31, 2014, our credit rating has been lowered below investment grade. As a result of this ratings action, we no longer have access to the Commercial Paper Program. Our available liquidity under the Commercial Paper Program will be replaced with borrowings under our Amended and Restated Credit Agreement. Additionally, as a result of this ratings action, interest rates and fees under our Amended and Restated Credit Agreement have increased.

Description of Business and Basis of Presentation Description of Business and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors.
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 in March 2014, an 80% interest in the Eagle Ford system, of which we acquired 46.67% and 33.33% from DCP Midstream, LLC in March 2013 and November 2012, respectively, and a 66.67% interest in the Southeast Texas system, which we acquired from DCP Midstream, LLC in March 2012. Prior to our acquisition of the additional 46.67% interest in the Eagle Ford system in March 2013, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to the March 2013 transaction, but prior to the acquisition of the remaining 20% interest in March 2014, we owned 80% of the Eagle Ford system which we accounted for as a consolidated subsidiary. These transfers of net assets between entities under common control were accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of our Lucerne 1 plant, our initial 80% interest in the Eagle Ford system and the remaining 66.67% interest in the Southeast Texas system for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in excess or in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction or an addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.
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.

- Definition

Disclosure of accounting policy for subsidiaries or other investments that are consolidated, including the accounting treatment for intercompany accounts or transactions and any noncontrolling interest.

+ References+ Details

- Definition

Disclosure of accounting policy for the equity method of accounting for investments in common stock or other interests including unconsolidated subsidiaries, corporate joint ventures, noncontrolling interests in real estate ventures, limited partnerships, and limited liability companies. The accounting policy may include information such as: (1) initially recording an investment in the stock of an investee at cost; (2) adjusting the carrying amount of the investment to recognize the investor's share of the earnings or losses of the investee after the date of acquisition; and (3) adjustments to reflect the investor's share of changes in the investee's capital (dividends). This disclosure may also include a detailed description of the policy for determining the amount of equity method losses recognized after an investment has been reduced to zero as a result of previous losses, reasons for not using the equity method when the investor company owns 20 percent or more of the voting stock of the investee's company (including identification of the significant investee), reasons for using the equity method when the ownership percentage is less than 20 percent, and discussion of recognition of equity method losses when an investor's total investment in an investee includes, in addition to an investment in common stock, other investments such as preferred stock and loans to the investee. An entity also may describe how such investments are assessed for impairment.

+ References+ Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Use of Estimates, Policy [Policy Text Block]

Cash and Cash Equivalents, Policy [Policy Text Block]

Allowance for Doubtful Accounts [Policy Text Block]

Inventory, Policy [Policy Text Block]

Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Derivatives, Policy [Policy Text Block]



Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Cash Flow Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (b)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

Other Non-Trading Derivative Activity	Mark-to-market method (c)	Net basis in gains and losses from commodity derivative activity

______________

(a)


(b)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.


(c)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

Interest Rate Risk

Property, Plant and Equipment, Policy [Policy Text Block]

Asset Retirement Obligations and Environmental Cost, Policy [Policy Text Block]

Goodwill and Intangible Assets, Policy [Policy Text Block]

Equity and Cost Method Investments, Policy [Policy Text Block]

Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block]


•	significant adverse change in legal factors or business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;


•	a significant adverse change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Debt, Policy [Policy Text Block]

Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]

The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control.

Revenue Recognition, Policy [Policy Text Block]

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

•


•	Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their customers.

Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:


•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.


•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.


•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Major Customers, Policy [Policy Text Block]

Environmental Costs, Policy [Policy Text Block]

Income Tax, Policy [Policy Text Block]

Earnings Per Share, Policy [Policy Text Block]

Fair Value Measurement Fair Value Measurement (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Fair Value Measurement, Policy [Policy Text Block]

Determination of Fair Value

•

Valuation Hierarchy


•	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.

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.

Interest Rate Derivative Assets and Liabilities

Nonfinancial Assets and Liabilities

Risk Management and Hedging Activities Derivatives, Methods of Accounting (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Derivatives, Policy [Policy Text Block]



Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Cash Flow Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (b)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

Other Non-Trading Derivative Activity	Mark-to-market method (c)	Net basis in gains and losses from commodity derivative activity

______________

(a)


(b)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.


(c)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

Interest Rate Risk

- Definition

Disclosure of accounting policy for its derivative instruments and hedging activities.

+ References+ Details

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]

For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:



Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Cash Flow Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (a)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (b)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

Other Non-Trading Derivative Activity	Mark-to-market method (c)	Net basis in gains and losses from commodity derivative activity

______________

(a)


(b)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.


(c)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2014

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the aggregate consideration and fair value of the identifiable assets acquired and liabilities assumed in the acquisition of Crossroads as of the acquisition date:



	July 3, 2012
	(Millions)
Aggregate consideration	$	63

Accounts receivable	$	4
Property, plant and equipment	63
Investments in unconsolidated affiliates	6
Other current liabilities	(4		)
Other long-term liabilities	(6		)
Total	$	63

Business Acquisition, Pro Forma Information



	Year Ended December 31, 2012
	DCP Midstream Partners, LP			Acquisition of Crossroads (a)		DCP Midstream Partners, LP Pro Forma
	(Millions)
Total operating revenues	$	2,824		$	27	$	2,851
Net income attributable to partners	$	216		$	2	$	218
Less:
Net income attributable to predecessor operations	(51		)	—		(51		)
General partner’s interest in net income	(41		)	—		(41		)
Net income allocable to limited partners	$	124		$	2	$	126

Net income per limited partner unit - basic and diluted	$	2.28		$	0.03	$	2.31


(a)	The year ended December 31, 2012 includes the financial results of Crossroads for the period from January 1, 2012 through July 2, 2012.

Income Statement [Member]

Business Acquisition [Line Items]

Schedule of Impact on Financial Statements Due to Acquisition

The following tables present the previously reported consolidated statements of operations for the years ended December 31, 2013 and 2012, condensed and adjusted for the acquisition of the Lucerne 1 plant from DCP Midstream, LLC:

Year Ended December 31, 2013



	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 Plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	2,695		$	68	$	2,763
Transportation, processing and other	268			3		271
Gains from commodity derivative activity, net	17			—		17
Total operating revenues	2,980			71		3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,381			45		2,426
Operating and maintenance expense	211			4		215
Depreciation and amortization expense	93			2		95
General and administrative expense	62			1		63
Other operating expense	8			—		8
Total operating costs and expenses	2,755			52		2,807
Operating income	225			19		244
Interest expense	(52		)	—		(52		)
Earnings from unconsolidated affiliates	33			—		33
Income before income taxes	206			19		225
Income tax expense	(8		)	—		(8		)
Net income	198			19		217
Net income attributable to noncontrolling interests	(17		)	—		(17		)
Net income attributable to partners	$	181		$	19	$	200

Year Ended December 31, 2012



	DCP Midstream Partners, LP (As previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
Sales of natural gas, propane, NGLs and condensate	$	2,459		$	61	$	2,520
Transportation, processing and other	232			2		234
Losses from commodity derivative activity, net	70			—		70
Total operating revenues	2,761			63		2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	2,177			38		2,215
Operating and maintenance expense	193			4		197
Depreciation and amortization expense	89			2		91
General and administrative expense	74			1		75
Total operating costs and expenses	2,533			45		2,578
Operating income	228			18		246
Interest expense	(42		)	—		(42		)
Earnings from unconsolidated affiliates	26			—		26
Income before income taxes	212			18		230
Income tax expense	(1		)	—		(1		)
Net income	211			18		229
Net income attributable to noncontrolling interests	(13		)	—		(13		)
Net income attributable to partners	$	198		$	18	$	216

Balance Sheet [Member]

Business Acquisition [Line Items]

Schedule of Impact on Financial Statements Due to Acquisition

The following table presents the previously reported December 31, 2013 consolidated balance sheet, condensed and adjusted for the acquisition of the Lucerne 1 plant from DCP Midstream, LLC:

As of December 31, 2013



	DCP Midstream Partners, LP (as previously reported on Form 10-K filed on 2/26/14)			Consolidate Lucerne 1 Plant		Consolidated DCP Midstream Partners, LP (As currently reported)
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	12		$	—	$	12
Accounts receivable	342			—		342
Inventories	67			—		67
Other	82			—		82
Total current assets	503			—		503
Property, plant and equipment, net	3,005			41		3,046
Goodwill and intangible assets, net	283			—		283
Investments in unconsolidated affiliates	627			—		627
Other non-current assets	108			—		108
Total assets	$	4,526		$	41	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	722		$	1	$	723
Long-term debt	1,590			—		1,590
Other long-term liabilities	41			—		41
Total liabilities	2,353			1		2,354
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity	1,956			40		1,996
Accumulated other comprehensive loss	(11		)	—		(11		)
Total partners’ equity	1,945			40		1,985
Noncontrolling interests	228			—		228
Total equity	2,173			40		2,213
Total liabilities and equity	$	4,526		$	41	$	4,567

Agreements and Transactions with Affiliates (Tables)

12 Months Ended

Dec. 31, 2014

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:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Services/Omnibus Agreement	$	41	$	29	$	26
Other fees — DCP Midstream, LLC	6		17		32
Total — DCP Midstream, LLC	$	47	$	46	$	58

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	2,179	$	1,830	$	1,691
Transportation, processing and other	$	92	$	60	$	52
Purchases of natural gas, propane and NGLs	$	194	$	204	$	173
Gains from commodity derivative activity, net	$	118	$	22	$	53
Operating and maintenance expense	$	1	$	1	$	1
General and administrative expense	$	47	$	46	$	58
Phillips 66:
Sales of natural gas, propane, NGLs and condensate	$	1	$	1	$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—	$	9
Transportation, processing and other	$	—	$	—	$	3
Purchases of natural gas, propane and NGLs	$	—	$	—	$	67
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	77	$	63	$	166
Transportation, processing and other	$	14	$	—	$	—
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs	$	—	$	—	$	2

We had balances with affiliates as follows:



	December 31, 2014		December 31, 2013
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	163	$	211
Accounts payable	$	24	$	37
Unrealized gains on derivative instruments — current	$	207	$	79
Unrealized gains on derivative instruments — long-term	$	25	$	81
Unrealized losses on derivative instruments — current	$	43	$	18
Unrealized losses on derivative instruments — long-term	$	—	$	1
Spectra Energy:
Accounts receivable	$	1	$	1
Accounts payable	$	3	$	6

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Classification of Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:



	Depreciable Life	December 31, 2014			December 31, 2013
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,209		$	2,205
Processing, storage, and terminal facilities	35 — 60 Years	2,071			1,645
Other	3 — 30 Years	50			49
Construction work in progress		281			310
Property, plant and equipment		4,611			4,209
Accumulated depreciation		(1,264		)	(1,163		)
Property, plant and equipment, net		$	3,347		$	3,046

Goodwill and Intangible assets Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:



	December 31,
	2014			2013
	(Millions)
Gross carrying amount	$	164		$	164
Accumulated amortization	(44		)	(35		)
Intangible assets, net	$	120		$	129

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(Millions)
2015	$	8
2016	8
2017	8
2018	8
2019	8
Thereafter	80
Total	$	120

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2014

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 Ownership	December 31, 2014		December 31, 2013
		(Millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	413	$	—
Discovery Producer Services LLC	40%	406		348
DCP Southern Hills Pipeline, LLC	33.33%	329		—
Front Range Pipeline LLC	33.33%	169		134
Texas Express Pipeline LLC	10%	98		96
Mont Belvieu Enterprise Fractionator	12.5%	23		26
Mont Belvieu 1 Fractionator	20%	14		16
Other	Various	7		7
Total investments in unconsolidated affiliates		$	1,459	$	627

Earnings from Investments in Unconsolidated Affiliates

Earnings (losses) from investments in unconsolidated affiliates were as follows:



	Year Ended December 31,
	2014		2013			2012
	(Millions)
DCP Sand Hills Pipeline, LLC	$	24	$	—		$	—
Mont Belvieu Enterprise Fractionator	16		14			5
DCP Southern Hills Pipeline, LLC	13		—			—
Mont Belvieu 1 Fractionator	12		19			6
Discovery Producer Services LLC	5		1			15
Texas Express Pipeline LLC	3		(1		)	—
Front Range Pipeline LLC	2		—			—
Total earnings from unconsolidated affiliates	$	75	$	33		$	26

Equity Method Investment Summarized Financial Information, Statement of Operations

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Statements of operations:
Operating revenue	$	826	$	484	$	293
Operating expenses	$	475	$	298	$	190
Net income	$	349	$	186	$	103

Equity Method Investment Summarized Financial Information, Balance Sheet



	December 31, 2014			December 31, 2013
	(Millions)
Balance sheets:
Current assets	$	207		$	182
Long-term assets	5,157			2,678
Current liabilities	(200		)	(276		)
Long-term liabilities	(164		)	(37		)
Net assets	$	5,000		$	2,547

Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Financial Instruments Carried at Fair Value



	December 31, 2014										December 31, 2013
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	92		$	138	$	230		$	—	$	14		$	65	$	79
Short-term investments (b)	$	24	$	—		$	—	$	24		$	9	$	—		$	—	$	9
Long-term assets (c):
Commodity derivatives	$	—	$	21		$	18	$	39		$	—	$	12		$	75	$	87
Current liabilities (d):
Commodity derivatives	$	—	$	(43	)	$	—	$	(43	)	$	—	$	(26	)	$	—	$	(26	)
Interest rate derivatives	$	—	$	—		$	—	$	—		$	—	$	(2	)	$	—	$	(2	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	—		$	—	$	—		$	—	$	(1	)	$	—	$	(1	)


(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.


(b)	Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.


(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.


(d)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.


(e)	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

Condensed Consolidated Balance Sheets for Derivative Financial Instruments



	Commodity Derivative Instruments
	Current Assets			Long- Term Assets			Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2014 (a):
Beginning balance	$	65		$	75		$	—		$	—
Net realized and unrealized gains (losses) included in earnings (c)	150			(57		)	—			—
Transfers out of Level 3 (b)	—			—			—			—
Settlements	(77		)	—			—			—
Purchases	—			—			—			—
Ending balance	$	138		$	18		$	—		$	—
Net unrealized gains (losses) on derivatives still held included in earnings (c)	$	138		$	(57	)	$	—		$	—
Year ended December 31, 2013 (a):
Beginning balance	$	40		$	65		$	(1	)	$	—
Net realized and unrealized gains (losses) included in earnings (c)	42			(50		)	—			—
Transfers out of Level 3 (b)	(1		)	(2		)	1			—
Settlements	(40		)	—			—			—
Purchases	24			62			—			—
Ending balance	$	65		$	75		$	—		$	—
Net unrealized gains (losses) on derivatives still held included in earnings (c)	$	41		$	(50	)	$	—		$	—


(a)	There were no issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2014 and 2013.


(b)	Amounts transferred into/out of Level 3 are reflected at fair value as of the end of the period.


(c)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

Schedule of Valuation Processes



	December 31, 2014
Product Group	Fair Value		Forward Curve Range
	(Millions)
Assets
NGLs	$	156	$0.17-$1.13	Per gallon

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

As of December 31, 2014 and December 31, 2013, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, were as follows:



		December 31, 2014				December 31, 2013
		Carrying Value		Fair Value		Carrying Value		Fair Value
	(Millions)

Long-Term Senior Notes		$	2,311	$	2,334	$	1,590	$	1,573

- Definition

Tabular disclosure of the fair value of financial instruments, including financial assets and financial liabilities, and the measurements of those instruments, assets, and liabilities.

+ References+ Details

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Schedule of Debt



	December 31, 2014			December 31, 2013
	(Millions)
Commercial Paper
Short-term borrowings, weighted-average interest rate of 1.14% as of December 31, 2013	$	—		$	335
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			—
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			—
Unamortized discount	(14		)	(10		)
Total debt	2,311			1,925
Short-term borrowings	—			(335		)
Current maturities of long-term debt	(250		)	—
Total long-term debt	$	2,061		$	1,590

Future Maturities of Long-Term Debt

The future maturities of long-term debt in the year indicated are as follows:



	Debt Maturities
	(Millions)
2015	$	250
2016	—
2017	500
2018	—
2019	325
Thereafter	1,250
	2,325
Unamortized discount	(14		)
Total	$	2,311

Risk Management and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2014

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:



	December 31, 2014									December 31, 2013
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	269		$	(42	)	$	227		$	166		$	(13	)	$	153
Liabilities:
Commodity derivatives	$	(43	)	$	42		$	(1	)	$	(27	)	$	13		$	(14	)
Interest rate derivatives	$	—		$	—		$	—		$	(2	)	$	—		$	(2	)


(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



Balance Sheet Line Item	December 31, 2014		December 31, 2013		Balance Sheet Line Item	December 31, 2014			December 31, 2013
	(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	$	230	$	79	Unrealized losses on derivative instruments — current	$	(43	)	$	(26	)
Unrealized gains on derivative instruments — long-term	39		87		Unrealized losses on derivative instruments — long-term	—			(1		)
	$	269	$	166		$	(43	)	$	(27	)
Interest rate derivatives:					Interest rate derivatives:
Unrealized gains on derivative instruments — current	$	—	$	—	Unrealized losses on derivative instruments — current	$	—		$	(2	)
Unrealized gains on derivative instruments — long-term	—		—		Unrealized losses on derivative instruments — long-term	—			—
	$	—	$	—		$	—		$	(2	)

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 year ended December 31, 2014:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(6	)		$	(6	)	$	1	$	(11	)
Losses reclassified from AOCI to earnings — effective portion	2			(b) (c)	—			—		2
Net deferred (losses) gains in AOCI (ending balance)	$	(4	)		$	(6	)	$	1	$	(9	)
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 consolidated statements of operations.


(c)	For the year ended December 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.

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 year ended December 31, 2013:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(10	)		$	(6	)	$	1	$	(15	)
Losses reclassified from AOCI to earnings — effective portion	$	4		(b)	$	—		$	—	$	4
Net deferred losses in AOCI (ending balance)	$	(6	)		$	(6	)	$	1	$	(11	)


(a)	Relates to Discovery, our unconsolidated affiliate.


(b)	Included in interest expense in our 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 consolidated statements of operations that such amounts are reflected:



Commodity Derivatives: Statements of Operations Line Item	Year Ended December 31,
	2014			2013			2012
	(Millions)
Third party:
Realized (losses) gains	$	(2	)	$	(19	)	$	4
Unrealized gains	38			14			13
Gains (losses) from commodity derivative activity, net	$	36		$	(5	)	$	17
Affiliates:
Realized gains	$	70		$	73		$	45
Unrealized gains (losses)	48			(51		)	8
Gains from commodity derivative activity, net —affiliates	$	118		$	22		$	53

Interest Rate Derivatives: Statements of Operations Line Item	Year Ended December 31,
	2014			2013			2012
	(Millions)
Third party:
Realized losses	$	(2	)	$	(2	)	$	(7	)
Unrealized gains	2			2			7
Interest expense	$	—		$	—		$	—

Schedule of Net Long or Short Positions Expected to be Realized



	December 31, 2014
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)		Net (Short) Position (MMBtu)		Net (Short) Position (Bbls)		Net Long Position (MMBtu)
2015	(745,695	)	(20,803,975	)	(5,573,570	)	2,640,000
2016	(561,922	)	(5,668,564	)	(813,267	)	1,690,000
2017	—		(6,387,500	)	—		—

	December 31, 2013
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net (Short) Position (Bbls)		Net (Short) Position (MMBtu)		Net (Short) Position (Bbls)		Net Long Position (MMBtu)
2014	(690,945	)	(21,673,620	)	(5,171,910	)	21,415,000
2015	(745,695	)	(9,458,975	)	(5,691,570	)	1,875,000
2016	(561,922	)	(1,838,564	)	(813,267	)	—

Partnership Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Cash Distribution

The following table presents our cash distributions paid in 2014, 2013 and 2012:



Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86
November 14, 2013	$	0.7200	$	82
August 14, 2013	$	0.7100	$	72
May 15, 2013	$	0.7000	$	69
February 14, 2013	$	0.6900	$	54
November 14, 2012	$	0.6800	$	53
August 14, 2012	$	0.6700	$	49
May 15, 2012	$	0.6600	$	43
February 14, 2012	$	0.6500	$	37

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Income tax expense consists of the following:



	Year Ended December 31,
	2014		2013		2012
	(Millions)
Current state income tax expense	$	3	$	3	$	1
Deferred state income tax expense	3		5		—
Total income tax expense	$	6	$	8	$	1

Business Segments (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment Information

The following tables set forth our segment information:

Year Ended December 31, 2014:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	3,163		$	73		$	406		$	—		$	3,642
Gross margin (a)	$	756		$	73		$	18		—			$	847
Operating and maintenance expense	(189		)	(16		)	(11		)	—			(216		)
Depreciation and amortization expense	(101		)	(7		)	(2		)	—			(110		)
General and administrative expense	—			—			—			(64		)	(64		)
Other expense	(2		)	(1		)	—			—			(3		)
Earnings from unconsolidated affiliates	5			70			—			—			75
Interest expense	—			—			—			(86		)	(86		)
Income tax expense	—			—			—			(6		)	(6		)
Net income (loss)	$	469		$	119		$	5		$	(156	)	$	437
Net income attributable to noncontrolling interests	(14		)	—			—			—			(14		)
Net income (loss) attributable to partners	$	455		$	119		$	5		$	(156	)	$	423
Non-cash derivative mark-to-market (b)	$	89		$	—		$	(3	)	$	—		$	86
Non-cash lower of cost or market adjustments	$	11		$	—		$	13		$	—		$	24
Capital expenditures	$	297		$	25		$	16		$	—		$	338
Acquisition expenditures	$	102		$	673		$	—		$	—		$	775
Investments in unconsolidated affiliates	$	75		$	76		$	—		$	—		$	151

Year Ended December 31, 2013:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,598		$	73		$	380		$	—		$	3,051
Gross margin (a)	$	501		$	72		$	52		$	—		$	625
Operating and maintenance expense	(184		)	(16		)	(15		)	—			(215		)
Depreciation and amortization expense	(87		)	(6		)	(2		)	—			(95		)
General and administrative expense	—			—			—			(63		)	(63		)
Other expense	(1		)	(3		)	(4		)	—			(8		)
Earnings from unconsolidated affiliates	1			32			—			—			33
Interest expense	—			—			—			(52		)	(52		)
Income tax expense	—			—			—			(8		)	(8		)
Net income (loss)	$	230		$	79		$	31		$	(123	)	$	217
Net income attributable to noncontrolling interests	(17		)	—			—			—			(17		)
Net income (loss) attributable to partners	$	213		$	79		$	31		$	(123	)	$	200
Non-cash derivative mark-to-market (b)	$	(36	)	$	—		$	(1	)	$	1		$	(36	)
Non-cash lower of cost or market adjustments	$	2		$	—		$	2		$	—		$	4
Capital expenditures	$	334		$	24		$	5		$	—		$	363
Acquisition expenditures	$	696		$	86		$	—		$	—		$	782
Investments in unconsolidated affiliates	$	133		$	109		$	—		$	—		$	242

Year Ended December 31, 2012:



	Natural Gas Services (c)			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	2,345		$	64		$	415		$	—		$	2,824
Gross margin (a)	$	503		$	64		$	42		$	—		$	609
Operating and maintenance expense	(166		)	(16		)	(15		)	—			(197		)
Depreciation and amortization expense	(83		)	(6		)	(2		)	—			(91		)
General and administrative expense	—			—			—			(75		)	(75		)
Earnings from unconsolidated affiliates	15			11			—			—			26
Interest expense	—			—			—			(42		)	(42		)
Income tax expense	—			—			—			(1		)	(1		)
Net income (loss)	$	269		$	53		$	25		$	(118	)	$	229
Net income attributable to noncontrolling interests	(13		)	—			—			—			(13		)
Net income (loss) attributable to partners	$	256		$	53		$	25		$	(118	)	$	216
Non-cash derivative mark-to-market (b)	$	20		$	—		$	1		$	—		$	21
Capital expenditures	$	468		$	12		$	4		$	—		$	484
Acquisitions net of cash acquired	$	715		$	30		$	—		$	—		$	745
Investments in unconsolidated affiliates	$	115		$	43		$	—		$	—		$	158



	December 31,		December 31,
	2014		2013
	(Millions)
Segment long-term assets:
Natural Gas Services (c)	$	3,609	$	3,303
NGL Logistics	1,364		555
Wholesale Propane Logistics	118		106
Other (d)	58		100
Total long-term assets	5,149		4,064
Current assets (c)	590		503
Total assets	$	5,739	$	4,567

(a)


(b)	Non-cash derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.

(c)


(d)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2014 and 2013 were as follows (millions, except per unit amounts):



2014	First (a)			Second		Third		Fourth			Year Ended December 31, 2014 (a)
Total operating revenues	$	1,081		$	812	$	868	$	881		$	3,642
Operating income	$	108		$	37	$	111	$	198		$	454
Net income	$	89		$	29	$	116	$	203		$	437
Net income attributable to noncontrolling interests	$	(10	)	$	—	$	—	$	(4	)	$	(14	)
Net income attributable to partners	$	79		$	29	$	116	$	199		$	423
Net income allocable to limited partners	$	47		$	2	$	86	$	168		$	303
Basic and diluted net income per limited partner unit	$	0.50		$	0.02	$	0.77	$	1.48		$	2.84



2013	First (a)(b)			Second (a)			Third (a)			Fourth (a)		Year Ended December 31, 2013 (a)
Total operating revenues	$	749		$	792		$	689		821		3,051
Operating income	$	65		$	117		$	14		48		244
Net income	$	60		$	111		$	6		40		217
Net income attributable to noncontrolling interests	$	(3	)	$	(4	)	$	(3	)	(7	)	(17	)
Net income attributable to partners	$	57		$	107		$	3		33		200
Net income (loss) allocable to limited partners	$	31		$	86		$	(20	)	8		105
Basic and diluted net income (loss) per limited partner unit	$	0.48		$	1.11		$	(0.24	)	0.09		1.34

(a)Our consolidated results of operations have been adjusted to retrospectively include the historical results of the Lucerne 1 plant for the periods presented.

(b)Our consolidated results of operations have been adjusted to retrospectively include the historical results of an 80% interest in the Eagle Ford system for the periods presented.

- Definition

+ References+ Details

Supplementary Information - Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Balance Sheets



	Condensed Consolidating Balance Sheet
	December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(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 Balance Sheet
	December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	12		$	—		$	12
Accounts receivable, net	—		—			342			—			342
Inventories	—		—			67			—			67
Other	—		—			82			—			82
Total current assets	—		—			503			—			503
Property, plant and equipment, net	—		—			3,046			—			3,046
Goodwill and intangible assets, net	—		—			283			—			283
Advances receivable — consolidated subsidiaries	1,805		1,683			—			(3,488		)	—
Investments in consolidated subsidiaries	181		426			—			(607		)	—
Investments in unconsolidated affiliates	—		—			627			—			627
Other long-term assets	—		12			96			—			108
Total assets	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	1	$	350		$	372		$	—		$	723
Advances payable — consolidated subsidiaries	—		—			3,488			(3,488		)	—
Long-term debt	—		1,590			—			—			1,590
Other long-term liabilities	—		—			41			—			41
Total liabilities	1		1,940			3,901			(3,488		)	2,354
Commitments and contingent liabilities
Equity:
Partners’ equity:
Predecessor equity	—		—			40			—			40
Net equity	1,985		187			391			(607		)	1,956
Accumulated other comprehensive loss	—		(6		)	(5		)	—			(11		)
Total partners’ equity	1,985		181			426			(607		)	1,985
Noncontrolling interests	—		—			228			—			228
Total equity	1,985		181			654			(607		)	2,213
Total liabilities and equity	$	1,986	$	2,121		$	4,555		$	(4,095	)	$	4,567


(a)	The financial information as of December 31, 2013 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.

Condensed Consolidating Statements of Operations



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	3,143		$	—		$	3,143
Transportation, processing and other	—		—			345			—			345
Gains from commodity derivative activity, net	—		—			154			—			154
Total operating revenues	—		—			3,642			—			3,642
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,795			—			2,795
Operating and maintenance expense	—		—			216			—			216
Depreciation and amortization expense	—		—			110			—			110
General and administrative expense	—		—			64			—			64
Other expense	—		—			3			—			3
Total operating costs and expenses	—		—			3,188			—			3,188
Operating income	—		—			454			—			454
Interest expense, net	—		(86		)	—			—			(86		)
Income from consolidated subsidiaries	423		509			—			(932		)	—
Earnings from unconsolidated affiliates	—		—			75			—			75
Income before income taxes	423		423			529			(932		)	443
Income tax expense	—		—			(6		)	—			(6		)
Net income	423		423			523			(932		)	437
Net income attributable to noncontrolling interests	—		—			(14		)	—			(14		)
Net income attributable to partners	$	423	$	423		$	509		$	(932	)	$	423


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,763		$	—		$	2,763
Transportation, processing and other	—		—			271			—			271
Gains from commodity derivative activity, net	—		—			17			—			17
Total operating revenues	—		—			3,051			—			3,051
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,426			—			2,426
Operating and maintenance expense	—		—			215			—			215
Depreciation and amortization expense	—		—			95			—			95
General and administrative expense	—		—			63			—			63
Other expense	—		—			8			—			8
Total operating costs and expenses	—		—			2,807			—			2,807
Operating income	—		—			244			—			244
Interest expense	—		(52		)	—			—			(52		)
Earnings from unconsolidated affiliates	—		—			33			—			33
Income from consolidated subsidiaries	200		252			—			(452		)	—
Income before income taxes	200		200			277			(452		)	225
Income tax expense	—		—			(8		)	—			(8		)
Net income	200		200			269			(452		)	217
Net income attributable to noncontrolling interests	—		—			(17		)	—			(17		)
Net income attributable to partners	$	200	$	200		$	252		$	(452	)	$	200

(a)



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	2,520		$	—		$	2,520
Transportation, processing and other	—		—			234			—			234
Gains from commodity derivative activity, net	—		—			70			—			70
Total operating revenues	—		—			2,824			—			2,824
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			2,215			—			2,215
Operating and maintenance expense	—		—			197			—			197
Depreciation and amortization expense	—		—			91			—			91
General and administrative expense	—		—			75			—			75
Total operating costs and expenses	—		—			2,578			—			2,578
Operating income	—		—			246			—			246
Interest expense	—		(41		)	(1		)	—			(42		)
Earnings from unconsolidated affiliates	—		—			26			—			26
Income from consolidated subsidiaries	216		257			—			(473		)	—
Income before income taxes	216		216			271			(473		)	230
Income tax expense	—		—			(1		)	—			(1		)
Net income	216		216			270			(473		)	229
Net income attributable to noncontrolling interests	—		—			(13		)	—			(13		)
Net income attributable to partners	$	216	$	216		$	257		$	(473	)	$	216

(a)

Condensed Consolidating Statements of Comprehensive Income



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	423	$	423	$	523		$	(932	)	$	437
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	425		425		523			(934		)	439
Total comprehensive income attributable to noncontrolling interests	—		—		(14		)	—			(14		)
Total comprehensive income attributable to partners	$	425	$	425	$	509		$	(934	)	$	425


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2012 (a)
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries				Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	216	$	216		$	270			$	(473	)	$	229
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings	—		10			—				—			10
Net unrealized losses on cash flow hedges	—		(1		)	—				—			(1		)
Other comprehensive income from consolidated subsidiaries	9		—			—				(9		)	—
Total other comprehensive income	9		9			—			—	(9		)	9
Total comprehensive income	225		225			270				(482		)	238
Total comprehensive income attributable to noncontrolling interests	—		—			(13		)		—			(13		)
Total comprehensive income attributable to partners	$	225	$	225		$	257			$	(482	)	$	225

(a)



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2013 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	200	$	200	$	269		$	(452	)	$	217
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		4		—			—			4
Other comprehensive income from consolidated subsidiaries	4		—		—			(4		)	—
Total other comprehensive income	4		4		—			(4		)	4
Total comprehensive income	204		204		269			(456		)	221
Total comprehensive income attributable to noncontrolling interests	—		—		(17		)	—			(17		)
Total comprehensive income attributable to partners	$	204	$	204	$	252		$	(456	)	$	204

(a)

Condensed Consolidating Statements of Cash Flows



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	—		(73	)	597		—		524
INVESTING ACTIVITIES:
Intercompany transfers	(581	)	(280	)	—		861		—
Capital expenditures	—		—		(338	)	—		(338	)
Acquisitions, net of cash acquired	—		—		(102	)	—		(102	)
Acquisition of unconsolidated affiliates	—		—		(673	)	—		(673	)
Investments in unconsolidated affiliates	—		—		(151	)	—		(151	)
Proceeds from sales of assets	—		—		28		—		28
Net cash used in investing activities	(581	)	(280	)	(1,236	)	861		(1,236	)
FINANCING ACTIVITIES:
Intercompany transfers	—		—		861		(861	)	—
Proceeds from long-term debt	—		719		—		—		719
Payments of commercial paper, net	—		(335	)	—		—		(335	)
Payments of deferred financing costs	—		(7	)	—		—		(7	)
Excess purchase price over acquired interests and commodity hedges	—		—		(18	)	—		(18	)
Proceeds from issuance of common units, net of offering costs	1,001		—		—		—		1,001
Net change in advances to predecessor from DCP Midstream, LLC	—		—		(6	)	—		(6	)
Distributions to limited partners and general partner	(420	)	—		—		—		(420	)
Distributions to noncontrolling interests	—		—		(14	)	—		(14	)
Purchase of additional interest in a subsidiary	—		—		(198	)	—		(198	)
Contributions from noncontrolling interests	—		—		3		—		3
Net cash provided by financing activities	581		377		628		(861	)	725
Net change in cash and cash equivalents	—		24		(11	)	—		13
Cash and cash equivalents, beginning of period	—		—		12		—		12
Cash and cash equivalents, end of period	—		24		1		—		25


(a)	The financial information for the year ended December 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 years are retrospectively adjusted to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2013 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(45	)	$	387		$	3		$	345
INVESTING ACTIVITIES:
Intercompany transfers	(806		)	(258		)	—			1,064			—
Capital expenditures	—			—			(363		)	—			(363		)
Acquisitions, net of cash acquired	—			—			(696		)	—			(696		)
Investments in unconsolidated affiliates	—			—			(242		)	—			(242		)
Acquisition of unconsolidated affiliates	—			—			(86		)	—			(86		)
Net cash used in investing activities	(806		)	(258		)	(1,387		)	1,064			(1,387		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,064			(1,064		)	—
Proceeds from long-term debt	—			1,957			—			—			1,957
Payments of long-term debt	—			(1,988		)	—			—			(1,988		)
Proceeds from issuance of commercial paper	—			335			—			—			335
Payment of deferred financing costs	—			(4		)	—			—			(4		)
Proceeds from issuance of common units, net of offering costs	1,083			—			—			—			1,083
Excess purchase price over acquired interests and commodity hedges	—			—			(85		)	—			(85		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			11			—			11
Distributions to limited partners and general partner	(277		)	—			—			—			(277		)
Distributions to noncontrolling interests	—			—			(24		)	—			(24		)
Contributions from noncontrolling interests	—			—			46			—			46
Distributions to DCP Midstream, LLC	—			—			(3		)	—			(3		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash provided by financing activities	806			300			1,010			(1,064		)	1,052
Net change in cash and cash equivalents	—			(3		)	10			3			10
Cash and cash equivalents, beginning of period	—			3			2			(3		)	2
Cash and cash equivalents, end of period	$	—		$	—		$	12		$	—		$	12

(a)



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2012 (a)
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(39	)	$	142		$	(1	)	$	102
INVESTING ACTIVITIES:
Intercompany transfers	(274		)	(827		)	—			1,101			—
Capital expenditures	—			—			(484		)	—			(484		)
Acquisitions, net of cash acquired	—			—			(745		)	—			(745		)
Investments in unconsolidated affiliates	—			—			(158		)	—			(158		)
Return of investment from unconsolidated affiliate	—			—			1			—			1
Proceeds from sale of assets	—			—			2			—			2
Net cash used in investing activities	(274		)	(827		)	(1,384		)	1,101			(1,384		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			1,101			(1,101		)	—
Proceeds from long-term debt	—			2,665			—			—			2,665
Payments of long-term debt	—			(1,792		)	—			—			(1,792		)
Payment of deferred financing costs	—			(8		)	—			—			(8		)
Proceeds from issuance of common units, net of offering costs	455			—			—			—			455
Excess purchase price over acquired assets	—			—			(225		)	—			(225		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			336			—			336
Distributions to common unitholders and general partner	(181		)	—			—			—			(181		)
Distributions to noncontrolling interests	—			—			(9		)	—			(9		)
Contributions from noncontrolling interests	—			—			25			—			25
Contributions from DCP Midstream, LLC	—			—			10			—			10
Net cash provided by financing activities	274			865			1,238			(1,101		)	1,276
Net change in cash and cash equivalents	—			(1		)	(4		)	(1		)	(6		)
Cash and cash equivalents, beginning of year	—			4			6			(2		)	8
Cash and cash equivalents, end of year	$	—		$	3		$	2		$	(3	)	$	2

(a)

Valuation and Qualifying Accounts and Reserves Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

Valuation and Qualifying Accounts and Reserves

Our valuation and qualifying accounts and reserves for the years ended December 31, 2014, 2013, and 2012 are as follows:



	Balance at Beginning of Period		Charged to Consolidated Statements of Operations		Charged to Other Accounts		Deductions/Other			Balance at End of Period
	(Millions)
December 31, 2014
Environmental	$	2	$	1	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	3	$	1	$	—	$	(1	)	$	3
December 31, 2013
Environmental	$	2	$	1	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	3	$	1	$	—	$	(1	)	$	3
December 31, 2012
Environmental	$	3	$	—	$	—	$	(1	)	$	2
Other (a)	1		—		—		—			1
	$	4	$	—	$	—	$	(1	)	$	3


(a)	Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in other long-term assets, and other contingency liabilities, which are included in other current liabilities.

Description of Business and Basis of Presentation - Additional Information (Detail)	12 Months Ended				12 Months Ended									12 Months Ended			12 Months Ended
	Dec. 31, 2014 Project	Dec. 31, 2013 Project	Dec. 31, 2014 Investments in Greater Than 20% [Member]	Dec. 31, 2014 Investments in Less Than 20% [Member]	Dec. 31, 2013 Eagle Ford System [Member]	Dec. 31, 2014 Eagle Ford System [Member]	Mar. 31, 2013 Eagle Ford System [Member]	Mar. 14, 2013 Eagle Ford System [Member]	Nov. 30, 2012 Eagle Ford System [Member]	Nov. 02, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Phillips 66 [Member]	Dec. 31, 2014 Spectra Energy [Member]	Dec. 31, 2014 DCP Midstream, LLC [Member]	Dec. 31, 2012 Southeast Texas [Member]	Mar. 31, 2012 Southeast Texas [Member]	Mar. 13, 2012 Southeast Texas [Member]	Dec. 31, 2013 Texas Express [Member]
Business Acquisition [Line Items]
Ownership interest percentage in subsidiary					80.00%									100.00%			10.00%
Number of owned and operated rail terminals	6
Marine Terminals	1
Pipeline Terminals		1
Equity Method Investment, Ownership Percentage			20.00%	20.00%						33.33%
Business Acquisition, Percentage of Voting Interests Acquired						20.00%	46.67%	46.67%	33.33%						66.67%	66.67%
Ownership interest percentage by parent	100.00%										50.00%	50.00%	22.00%

Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Customer	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Significant Customers	0
Significant Customers Percentage Accounted Of Total Revenue	10.00%
Accrued Environmental Loss Contingencies, Current	$ 1	$ 1
Accrued Environmental Loss Contingencies, Noncurrent	$ 1	$ 1

- Definition

Carrying value of the obligation (known or estimated) arising from requirements to perform activities to remediate one or more sites, payable in twelve months or in the next operating cycle if longer.

+ References+ Details

- Definition

Carrying value of the obligation (known or estimated) arising from requirements to perform activities to remediate one or more sites, payable after twelve months or beyond the next operating cycle if longer.

+ References+ Details

Acquisitions - Additional Information (Detail) (USD $)	3 Months Ended								12 Months Ended					12 Months Ended	1 Months Ended		12 Months Ended					12 Months Ended									0 Months Ended	12 Months Ended	0 Months Ended
Acquisitions - Additional Information (Detail) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Feb. 29, 2012	Dec. 31, 2012 Contractual Processing Arrangement [Member]	Mar. 31, 2013 Eagle Ford System [Member]	Nov. 30, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Eagle Ford System [Member]	Dec. 31, 2013 Eagle Ford System [Member]	Dec. 31, 2012 Eagle Ford System [Member]	Mar. 14, 2013 Eagle Ford System [Member]	Nov. 02, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Southern Hills Pipeline [Member] MBbls	Dec. 31, 2014 Southern Hills Pipeline [Member] Ngl Pipeline [Member] mi	Dec. 31, 2014 Lucerne 1 [Member] MMcf	Dec. 31, 2013 Lucerne 1 [Member]	Dec. 31, 2012 Lucerne 1 [Member]	Dec. 31, 2014 Lucerne 2 [Member] MMcf	Dec. 31, 2014 Lucerne 2 [Member] Subsequent Event [Member]	Dec. 31, 2014 Sand Hills Pipeline [Member] MBbls	Dec. 31, 2014 Sand Hills Pipeline [Member] Ngl Pipeline [Member] mi	Jul. 03, 2012 Crossroads System [Member] MMcf	Dec. 31, 2012 Crossroads System [Member]	Jul. 03, 2012 Crossroads System [Member] Gas Gathering Pipeline [Member] mi	Jul. 03, 2012 Crossroads System [Member] Ngl Pipeline [Member] mi	Jul. 03, 2012 Crossroads System [Member] Residue Gas Pipeline [Member] mi
Business Acquisition [Line Items]
Total operating revenues	$ 881,000,000	$ 868,000,000	$ 812,000,000	$ 1,081,000,000	$ 821,000,000	$ 689,000,000	$ 792,000,000	$ 749,000,000	$ 3,642,000,000	$ 3,051,000,000	$ 2,824,000,000			$ 5,000,000											$ 71,000,000	$ 63,000,000
Aggregate consideration for acquisition									1,220,000,000																						63,000,000
Expected capacity per day																						175							200
Business Acquisition, Percentage of Voting Interests Acquired															46.67%	33.33%	20.00%			46.67%															50.00%
Partners Capital Account Acquisitions Issuance Of Units																	225,000,000	125,000,000	88,000,000
Common unitholders, units issued	113,949,868				89,045,139				113,949,868	89,045,139		5,148,500	30,701
Ownership interest percentage in subsidiary																		80.00%
Remaining consideration financed through issuance of common units, value																	999,368					2,098,674							1,399,116
Issuance of common units															2,789,739	1,912,663
Equity Method Investment, Ownership Percentage																					33.33%								33.33%
Pipeline Length In Miles																							940							1,025			8	20	11
Capacity Of Plants or Pipelines Per Day																								35			200				80
Percentage of plant's capacity upon which a fixed demand fee is charged																								75.00%			75.00%	43.00%
Revenues of acquiree																																22,000,000
Earnings (loss) of acquiree																																1,000,000
Excess Purchase Price Over Acquired Assets																	$ 178,000,000		$ 42,000,000

Acquisitions - Schedule of Impact on Financial Statements Due to Acquisition, Balance Sheets (Detail) (USD $)	12 Months Ended				0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jul. 03, 2012 Crossroads System [Member]	Dec. 31, 2013 DCP Midstream Partners, LP (As Previously Reported) [Member]	Dec. 31, 2013 Scenario, Adjustment [Member] Lucerne 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Business Combination, Consideration Transferred	$ 1,220,000,000				$ 63,000,000
Current assets:
Cash and cash equivalents	25,000,000	12,000,000	2,000,000	8,000,000		12,000,000	0
Accounts receivable		342,000,000				342,000,000	0
Inventories	63,000,000	67,000,000				67,000,000	0
Other	232,000,000	82,000,000				82,000,000	0
Total current assets	590,000,000	503,000,000				503,000,000	0
Property, plant and equipment, net	3,347,000,000	3,046,000,000				3,005,000,000	41,000,000
Goodwill and intangible assets, net	274,000,000	283,000,000				283,000,000	0
Investments in unconsolidated affiliates	1,459,000,000	627,000,000				627,000,000	0
Other non-current assets	69,000,000	108,000,000				108,000,000	0
Total assets	5,739,000,000	4,567,000,000				4,526,000,000	41,000,000
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	601,000,000	723,000,000				722,000,000	1,000,000
Long-term debt	2,061,000,000	1,590,000,000				1,590,000,000	0
Other long-term liabilities	51,000,000	41,000,000				41,000,000	0
Total liabilities	2,713,000,000	2,354,000,000				2,353,000,000	1,000,000
Commitments and contingent liabilities
Equity:
Net equity		1,996,000,000				1,956,000,000	40,000,000
Accumulated other comprehensive loss	(9,000,000)	(11,000,000)				(11,000,000)	0
Total partners' equity	2,993,000,000	1,985,000,000				1,945,000,000	40,000,000
Noncontrolling interests	33,000,000	228,000,000				228,000,000	0
Total equity	3,026,000,000	2,213,000,000	1,636,000,000	1,605,000,000		2,173,000,000	40,000,000
Total liabilities and equity	5,739,000,000	4,567,000,000				4,526,000,000	41,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables					4,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					63,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Investment In Unconsolidated Affiliates					6,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other					(4,000,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other					(6,000,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					$ 63,000,000

Acquisitions - Schedule of Impact on Financial Statements Due to Acquisition, Statement of Operations (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									$ 3,143	$ 2,763	$ 2,520
Transportation, processing and other									345	271	234
Gain (Loss) on Derivative Instruments, Net, Pretax									154	17	70
Total operating revenues	881	868	812	1,081	821	689	792	749	3,642	3,051	2,824
Operating costs and expenses
Purchases of natural gas, propane and NGLs									2,795	2,426	2,215
Operating and maintenance expense									216	215	197
Depreciation and amortization expense									110	95	91
General and administrative expense									64	63	75
Other expense (income)									3	8	0
Total operating costs and expenses									3,188	2,807	2,578
Operating Income (Loss)	198	111	37	108	48	14	117	65	454	244	246
Interest expense									(86)	(52)	(42)
Earnings from unconsolidated affiliates									75	33	26
Income before income taxes									443	225	230
Income tax expense									(6)	(8)	(1)
Net income	203	116	29	89	40	6	111	60	437	217	229
Net income attributable to noncontrolling interests	(4)	0	0	(10)	(7)	(3)	(4)	(3)	(14)	(17)	(13)
Net income attributable to partners	199	116	29	79	33	3	107	57	423	200	216
Gains from commodity derivative activity, net											70
Net income attributable to predecessor operations									(6)	(25)	(51)
General partner's interest in net income									(114)	(70)	(41)
Net Income (Loss) Allocated to Limited Partners	168	86	2	47	8	(20)	86	31	303	105	124
Dcp Midstream Lp [Member]
Condensed Financial Statements, Captions [Line Items]
Natural Gas Midstream Revenue											2,824
Operating costs and expenses
Net income attributable to partners											216
Net income attributable to predecessor operations											(51)
General partner's interest in net income											(41)
Net Income (Loss) Allocated to Limited Partners											124
Business Acquisition Pro Forma Earnings Per Share Basic And Diluted											$ 2.28
Lucerne 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate										68	61
Transportation, processing and other										3	2
Gain (Loss) on Derivative Instruments, Net, Pretax										0
Total operating revenues										71	63
Operating costs and expenses
Purchases of natural gas, propane and NGLs										45	38
Operating and maintenance expense										4	4
Depreciation and amortization expense										2	2
General and administrative expense										1	1
Other expense (income)										0
Total operating costs and expenses										52	45
Operating Income (Loss)										19	18
Interest expense										0	0
Earnings from unconsolidated affiliates										0	0
Income before income taxes										19	18
Income tax expense										0	0
Net income										19	18
Net income attributable to noncontrolling interests										0	0
Net income attributable to partners										19	18
Gains from commodity derivative activity, net											0
Crossroads System [Member]
Condensed Financial Statements, Captions [Line Items]
Natural Gas Midstream Revenue											27
Operating costs and expenses
Net income attributable to partners											2
Net Income (Loss) Allocated to Limited Partners											2
Business Acquisition Pro Forma Earnings Per Share Basic And Diluted											$ 0.03
Dcp Midstream Partners Lp Pro Forma [Member]
Condensed Financial Statements, Captions [Line Items]
Natural Gas Midstream Revenue											2,851
Operating costs and expenses
Net income attributable to partners											218
Net income attributable to predecessor operations											(51)
General partner's interest in net income											(41)
Net Income (Loss) Allocated to Limited Partners											126
Business Acquisition Pro Forma Earnings Per Share Basic And Diluted											$ 2.31
DCP Midstream Partners, LP (as Previously Reported 2/26/14) [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate											2,459
Transportation, processing and other											232
Total operating revenues											2,761
Operating costs and expenses
Purchases of natural gas, propane and NGLs											2,177
Operating and maintenance expense											193
Depreciation and amortization expense											89
General and administrative expense											74
Total operating costs and expenses											2,533
Operating Income (Loss)											228
Interest expense											(42)
Earnings from unconsolidated affiliates											26
Income before income taxes											212
Income tax expense											(1)
Net income											211
Net income attributable to noncontrolling interests											(13)
Net income attributable to partners											198
Gains from commodity derivative activity, net											70
DCP Midstream Partners, LP (As Previously Reported) [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate										2,695
Transportation, processing and other										268
Gain (Loss) on Derivative Instruments, Net, Pretax										17
Total operating revenues										2,980
Operating costs and expenses
Purchases of natural gas, propane and NGLs										2,381
Operating and maintenance expense										211
Depreciation and amortization expense										93
General and administrative expense										62
Other expense (income)										8
Total operating costs and expenses										2,755
Operating Income (Loss)										225
Interest expense										(52)
Earnings from unconsolidated affiliates										33
Income before income taxes										206
Income tax expense										(8)
Net income										198
Net income attributable to noncontrolling interests										(17)
Net income attributable to partners										$ 181

Agreements and Transactions with Affiliates - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

3 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

DCP Midstream, LLC [Member]

Dec. 31, 2013

DCP Midstream, LLC [Member]

Dec. 31, 2012

DCP Midstream, LLC [Member]

Dec. 31, 2013

Lucerne 1 [Member]

Dec. 31, 2013

Lucerne 1 [Member]

Dec. 31, 2012

Lucerne 1 [Member]

Apr. 30, 2012

Spectra Energy [Member]

gal

Dec. 31, 2014

Eagle Ford System [Member]

Dec. 31, 2013

Eagle Ford System [Member]

Dec. 31, 2012

Eagle Ford System [Member]

Mar. 31, 2013

Eagle Ford System [Member]

Mar. 14, 2013

Eagle Ford System [Member]

Nov. 30, 2012

Eagle Ford System [Member]

Dec. 31, 2013

Southeast Texas [Member]

Dec. 31, 2012

Southeast Texas [Member]

Mar. 31, 2012

Southeast Texas [Member]

Mar. 13, 2012

Southeast Texas [Member]

Dec. 31, 2013

East Texas System [Member]

Dec. 31, 2012

East Texas System [Member]

Jan. 31, 2012

East Texas System [Member]

Dec. 31, 2014

Affiliated Entity [Member]

DCP Midstream, LLC [Member]

Dec. 31, 2013

Affiliated Entity [Member]

DCP Midstream, LLC [Member]

Dec. 31, 2012

Affiliated Entity [Member]

DCP Midstream, LLC [Member]

Dec. 31, 2014

Affiliated Entity [Member]

Lucerne 1 [Member]

Dec. 31, 2014

Affiliated Entity [Member]

Spectra Energy [Member]

Dec. 31, 2013

Affiliated Entity [Member]

Spectra Energy [Member]

Dec. 31, 2014

Affiliated Entity [Member]

ConocoPhillips [Member]

Dec. 31, 2013

Affiliated Entity [Member]

ConocoPhillips [Member]

Dec. 31, 2012

Affiliated Entity [Member]

ConocoPhillips [Member]

Dec. 31, 2014

Affiliated Entity [Member]

O'Connor Plant [Member]

Dec. 31, 2013

Affiliated Entity [Member]

O'Connor Plant [Member]

Mar. 31, 2015

Subsequent Event [Member]

Services Agreement Amendment Increase

$ 15

$ 25

Business Acquisition, Percentage of Voting Interests Acquired

20.00%

46.67%

33.33%

66.67%

49.90%

Services agreement

General and administrative expenses incurred

Other fees - DCP Midstream, LLC

Contributions from DCP Midstream, LLC

Transportation, processing and other

345

271

234

^[1]

Natural Gas Propane Ngls Condensate Revenue

Transportation Processing And Other To Affiliates

Net income attributable to noncontrolling interests

Terms of agreement

10 years

Operating and maintenance expense

$ 216

$ 215

$ 197

$ 4

$ 1

Propane supply agreement (in gallons per year)

185,000,000

Ownership interest percentage in subsidiary

80.00%

100.00%

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjA1ZGU2NzE4NjQ5MTQ3M2NiMWM0NmUxMzBjMjQ5MGJlfFRleHRTZWxlY3Rpb246RkI5MkQwM0Q4RTI3NEQzRDc4N0ZBMDg2MTA2RjQ5OEUM}

Agreements and Transactions with Affiliates - Schedule of Fees Incurred and Other Fees Paid (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Services/Omnibus Agreement	$ 41	$ 29	$ 26
Other fees - DCP Midstream, LLC	6	17	32
Total - DCP Midstream, LLC	64	63	75
DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC	2	2	1
DCP Midstream, LLC [Member] \| Affiliated Entity [Member]
Total - DCP Midstream, LLC	$ 47	$ 46	$ 58

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Sales of natural gas, propane, NGLs and condensate

$ 3,143

$ 2,763

$ 2,520

Transportation, processing and other

345

271

234

Purchases of natural gas, propane and NGLs

2,795

2,426

2,215

Gain (Loss) on Derivative Instruments, Net, Pretax

154

Operating and maintenance expense

216

215

197

General and administrative expense

Affiliated Entity [Member] | DCP Midstream, LLC [Member]

Sales of natural gas, propane, NGLs and condensate

2,179

1,830

1,691

Transportation, processing and other

Purchases of natural gas, propane and NGLs

194

204

173

Operating and maintenance expense

General and administrative expense

Affiliated Entity [Member] | DCP Midstream, LLC [Member] | Commodity Derivatives [Member]

Gain (Loss) on Derivative Instruments, Net, Pretax

118

Affiliated Entity [Member] | Phillips 66 [Member]

Sales of natural gas, propane, NGLs and condensate

Affiliated Entity [Member] | ConocoPhillips [Member]

Sales of natural gas, propane, NGLs and condensate

^[1]

Transportation, processing and other

^[1]

Purchases of natural gas, propane and NGLs

^[1]

Affiliated Entity [Member] | Spectra Energy [Member]

Transportation, processing and other

Purchases of natural gas, propane and NGLs

166

Affiliated Entity [Member] | Unconsolidated Affiliates [Member]

Purchases of natural gas, propane and NGLs

$ 0

$ 2

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjA1ZGU2NzE4NjQ5MTQ3M2NiMWM0NmUxMzBjMjQ5MGJlfFRleHRTZWxlY3Rpb246RkI5MkQwM0Q4RTI3NEQzRDc4N0ZBMDg2MTA2RjQ5OEUM}

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Accounts receivable	$ 164	$ 212
Accounts payable	27	43
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Accounts receivable	163	211
Accounts payable	24	37
Unrealized gains on derivative instruments - current	207	79
Unrealized gains on derivative instruments - long-term	25	81
Unrealized losses on derivative instruments - current	43	18
Unrealized losses on derivative instruments - long-term	0	1
Spectra Energy [Member]
Related Party Transaction [Line Items]
Accounts receivable	1	1
Accounts payable	$ 3	$ 6

- Definition

Amount for accounts payable to related parties. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

+ References+ Details

- Definition

Amount of receivables arising from transactions with related parties due within one year or the normal operating cycle, if longer.

+ References+ Details

Inventories - Schedule of Inventories (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components Of Inventory [Line Items]
Inventory Write-down	$ 24	$ 4	$ 19
Total inventories	63	67
Natural Gas [Member]
Components Of Inventory [Line Items]
Total inventories	36	38
Natural Gas Liquids [Member]
Components Of Inventory [Line Items]
Total inventories	$ 27	$ 29

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) (USD $) In Millions, unless otherwise specified					12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014 Gathering and Transmission Systems [Member]	Dec. 31, 2013 Gathering and Transmission Systems [Member]	Dec. 31, 2014 Gathering and Transmission Systems [Member] Minimum [Member]	Dec. 31, 2014 Gathering and Transmission Systems [Member] Maximum [Member]	Dec. 31, 2014 Processing, Storage, and Terminal Facilities [Member]	Dec. 31, 2013 Processing, Storage, and Terminal Facilities [Member]	Dec. 31, 2014 Processing, Storage, and Terminal Facilities [Member] Minimum [Member]	Dec. 31, 2014 Processing, Storage, and Terminal Facilities [Member] Maximum [Member]	Dec. 31, 2014 Other Energy Equipment [Member]	Dec. 31, 2013 Other Energy Equipment [Member]	Dec. 31, 2014 Other Energy Equipment [Member] Minimum [Member]	Dec. 31, 2014 Other Energy Equipment [Member] Maximum [Member]	Dec. 31, 2014 Construction Work In Progress [Member]	Dec. 31, 2013 Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment					20 years	50 years			35 years	60 years			3 years	30 years
Property, plant and equipment	$ 4,611	$ 4,209	$ 2,209	$ 2,205			$ 2,071	$ 1,645			$ 50	$ 49			$ 281	$ 310
Accumulated depreciation	(1,264)	(1,163)
Property, plant and equipment, net	$ 3,347	$ 3,046

Property, Plant and Equipment - Additional Information (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Interest capitalized on construction projects	$ 8	$ 11	$ 7
Basic earnings per share adjustment, pro forma			$ 0.95
Depreciation expense	101	87	83
Assets Disposed of by Method Other than Sale, in Period of Disposition, Gain (Loss) on Disposition	(3)	(8)
Asset Retirement Obligation, Revision of Estimate	1
Asset Retirement Obligation, Accretion Expense	(2)	(1)	(1)
Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Reduction in depreciation expense			52
Asset Retirement Obligations, Noncurrent	$ 27	$ 24

Goodwill and Intangible assets Schedule of Finite-Lived Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Finite-Lived Intangible Assets, Gross	$ 164	$ 164
Finite-Lived Intangible Assets, Accumulated Amortization	(44)	(35)
Intangible assets, net	120	129
Amortization of Intangible Assets	$ 9	$ 8	$ 8

Goodwill and Intangible assets Finite-Lived Intangible Assets, Future Amortization (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	$ 8
Finite-Lived Intangible Assets, Amortization Expense, Year Two	8
Finite-Lived Intangible Assets, Amortization Expense, Year Three	8
Finite-Lived Intangible Assets, Amortization Expense, Year Four	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	8
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	$ 80
Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	7 years
Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	21 years
Weighted Average [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	16 years

Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 1,459	$ 627
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	413	0
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Investments in unconsolidated affiliates	406	348
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	329	0
Front Range Pipeline LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	169	134
Texas Express Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Investments in unconsolidated affiliates	98	96
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	12.50%
Investments in unconsolidated affiliates	23	26
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Investments in unconsolidated affiliates	14	16
Other [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage description	Various
Investments in unconsolidated affiliates	$ 7	$ 7

Investments In Unconsolidated Affiliates - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	$ 8
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	10
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	(25)	(28)
Front Range Pipeline LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	5	4
Texas Express Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	3	3
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	$ (4)	$ (5)

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 75	$ 33	$ 26
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	24	0	0
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	12	19	6
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	13	0	0
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	16	14	5
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	5	1	15
Texas Express [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	3	(1)	0
Front Range [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 2	$ 0

- Definition

This item represents the entity's proportionate share for the period of the net income (loss) of its investee (such as unconsolidated subsidiaries and joint ventures) to which the equity method of accounting is applied. This item includes income or expense related to stock-based compensation based on the investor's grant of stock to employees of an equity method investee.

+ References+ Details

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 826	$ 484	$ 293
Operating expenses	475	298	190
Net income	$ 349	$ 186	$ 103

- Definition

The amount of net income (loss) reported by an equity method investment of the entity.

+ References+ Details

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 207	$ 182
Long-term assets	5,157	2,678
Current liabilities	(200)	(276)
Long-term liabilities	(164)	(37)
Net assets	$ 5,000	$ 2,547

- Definition

The amount of assets reported by an equity method investment of the entity.

+ References+ Details

- Definition

The amount of current assets reported by an equity method investment of the entity.

+ References+ Details

- Definition

The amount of current liabilities reported by an equity method investment of the entity.

+ References+ Details

- Definition

The amount of noncurrent assets reported by an equity method investment of the entity.

+ References+ Details

- Definition

The amount of noncurrent liabilities reported by an equity method investment of the entity.

+ References+ Details

Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) (USD $)

Dec. 31, 2014

Dec. 31, 2013

Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Short-term investments

$ 24,000,000

$ 9,000,000

Commodity Derivative [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

230,000,000

^[1]

79,000,000

^[1]

Commodity Derivative [Member] | Long-Term Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

39,000,000

^[2]

87,000,000

^[2]

Commodity Derivative [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

(43,000,000)

^[3]

(26,000,000)

^[3]

Commodity Derivative [Member] | Long-Term Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[4]

(1,000,000)

^[4]

Interest Rate Derivatives [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Interest rate derivatives

^[3]

(2,000,000)

^[3]

Level 1 [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Short-term investments

24,000,000

9,000,000

Level 1 [Member] | Commodity Derivative [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[1]

Level 1 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[2]

Level 1 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[3]

Level 1 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[4]

Level 1 [Member] | Interest Rate Derivatives [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Interest rate derivatives

^[3]

Level 2 [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Short-term investments

Level 2 [Member] | Commodity Derivative [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

92,000,000

^[1]

14,000,000

^[1]

Level 2 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

21,000,000

^[2]

12,000,000

^[2]

Level 2 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

(43,000,000)

^[3]

(26,000,000)

^[3]

Level 2 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[4]

(1,000,000)

^[4]

Level 2 [Member] | Interest Rate Derivatives [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Interest rate derivatives

^[3]

(2,000,000)

^[3]

Level 3 [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Short-term investments

Level 3 [Member] | Commodity Derivative [Member] | Current Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

138,000,000

^[1]

65,000,000

^[1]

Level 3 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

18,000,000

^[2]

75,000,000

^[2]

Level 3 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[3]

Level 3 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Commodity derivatives

^[4]

Level 3 [Member] | Interest Rate Derivatives [Member] | Current Liabilities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Interest rate derivatives

$ 0

^[3]

$ 0

^[3]

[1]	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.
[2]	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.
[3]	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
[4]	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Current Assets [Member]

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning balance

$ 65

^[1]

$ 40

^[1]

Net realized and unrealized gains (losses) included in earnings

150

^[1],[2]

Transfers out of Level 3

^[1],[3]

(1)

^[1],[3]

Settlements

(77)

^[1]

(40)

^[1]

Purchases

^[1]

Ending balance

138

^[1]

Net unrealized gains still held included in earnings

138

^[1],[2]

Long-Term Assets [Member]

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning balance

^[1]

Net realized and unrealized gains (losses) included in earnings

(57)

^[1],[2]

(50)

^[1],[2]

Transfers out of Level 3

^[1],[3]

(2)

^[1],[3]

Settlements

^[1]

Purchases

^[1]

Ending balance

^[1]

Net unrealized gains still held included in earnings

(57)

^[1],[2]

(50)

^[1],[2]

Current Liabilities [Member]

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning balance

^[1]

(1)

^[1]

Net realized and unrealized (losses) gains included in earnings

^[1],[2]

Transfers out of Level 3

^[1],[3]

Settlements

^[1]

Purchases

^[1]

Ending balance

^[1]

Net unrealized gains (losses) still held included in earnings

^[1],[2]

Long-Term Liabilities [Member]

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning balance

^[1]

Net realized and unrealized (losses) gains included in earnings

^[1],[2]

Transfers out of Level 3

^[1],[3]

Settlements

^[1]

Purchases

^[1]

Ending balance

^[1]

Net unrealized gains (losses) still held included in earnings

$ 0

^[1],[2]

$ 0

^[1],[2]

[1]	There were no issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2014 and 2013.
[2]	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.
[3]	Amounts transferred into/out of Level 3 are reflected at fair value as of the end of the period.

Fair Value Measurement - Schedule of Valuation Processes (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014 Fair Value, Inputs, Level 3 [Member] Market Approach Valuation Technique [Member] Derivative Financial Instruments, Assets [Member] Natural Gas Liquids [Member]	Dec. 31, 2014 Minimum [Member] Fair Value, Inputs, Level 3 [Member] Market Approach Valuation Technique [Member] Derivative Financial Instruments, Assets [Member] Natural Gas Liquids [Member]	Dec. 31, 2014 Maximum [Member] Fair Value, Inputs, Level 3 [Member] Market Approach Valuation Technique [Member] Derivative Financial Instruments, Assets [Member] Natural Gas Liquids [Member]	Dec. 31, 2014 Senior Notes, 3.25% Due 2015 [Member]	Dec. 31, 2014 Senior Notes, 2.50% Due 2017 [Member]	Nov. 27, 2012 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]	Dec. 31, 2014 Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]	Dec. 31, 2014 Senior Notes, 4.95% Due 2022 [Member]	Dec. 31, 2014 Senior Notes, 3.875% Due 2023 [Member]	Mar. 14, 2013 Senior Notes, 3.875% Due 2023 [Member]	Dec. 31, 2014 Derivative Financial Instruments, Liabilities [Member] Minimum [Member] Fair Value, Inputs, Level 3 [Member] Market Approach Valuation Technique [Member] Natural Gas Liquids [Member]	Dec. 31, 2014 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]
Fair Value, Assets	$ 156
Forward Curve Range		0.17	1.13									0.00	0.00
Senior notes interest rate percentage				3.25%	2.50%	2.50%	5.60%	2.70%	4.95%	3.875%	3.875%

Fair Value Measurement - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014 Senior Notes, 3.875% Due 2023 [Member]	Mar. 14, 2013 Senior Notes, 3.875% Due 2023 [Member]	Dec. 31, 2014 Senior Notes, 2.50% Due 2017 [Member]	Nov. 27, 2012 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]	Dec. 31, 2014 Senior Notes, 4.95% Due 2022 [Member]	Dec. 31, 2014 Senior Notes, 3.25% Due 2015 [Member]	Dec. 31, 2014 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			3.875%	3.875%	2.50%	2.50%	2.70%	4.95%	3.25%	5.60%
Debt Instrument, Carrying Amount	$ 2,311	$ 1,590
Debt Instrument, Fair Value	$ 2,334	$ 1,573

Debt - Schedule of Long-Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Mar. 14, 2013
Line of Credit Facility [Line Items]
Short-term borrowings	$ 0	$ (335,000,000)
Long-term Debt, Current Maturities	250,000,000	0
Unamortized discount	(14,000,000)	(10,000,000)
Total	2,311,000,000	1,925,000,000
Total long-term debt	2,061,000,000	1,590,000,000
Senior Notes, 3.875% Due 2023 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	500,000,000	500,000,000	500,000,000
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	400,000,000	0
Senior Notes, 2.50% Due 2017 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	500,000,000	500,000,000
Senior Notes, 4.95% Due 2022 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	350,000,000	350,000,000
Senior Notes, 3.25% Due 2015 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	250,000,000	250,000,000
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount	325,000,000	0
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Short-term borrowings	$ 0	$ (335,000,000)

- Definition

Reflects the total carrying amount as of the balance sheet date of debt having initial terms less than one year or the normal operating cycle, if longer.

+ References+ Details

Debt - Schedule of Long-Term Debt (Parenthetical) (Detail)	12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2014 Credit Agreement [Member]	Dec. 31, 2013 Commercial Paper [Member]	Dec. 31, 2014 Senior Notes, 3.875% Due 2023 [Member]	Mar. 14, 2013 Senior Notes, 3.875% Due 2023 [Member]	Dec. 31, 2014 Senior Notes, 2.50% Due 2017 [Member]	Nov. 27, 2012 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes, 4.95% Due 2022 [Member]	Dec. 31, 2014 Senior Notes, 3.25% Due 2015 [Member]
Line of Credit Facility [Line Items]
Weighted-average variable interest rate		1.14%
Line of credit facility, maturity date	Nov. 10, 2016
Senior notes interest rate percentage			3.875%	3.875%	2.50%	2.50%	4.95%	3.25%
Maturity date			Mar. 15, 2023		Dec. 01, 2017		Apr. 01, 2022	Oct. 01, 2015

Debt - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended			3 Months Ended			0 Months Ended	12 Months Ended		0 Months Ended	12 Months Ended		12 Months Ended		12 Months Ended													12 Months Ended
Debt - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014 Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]	Dec. 31, 2014 Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]	Dec. 31, 2013 Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]	Mar. 31, 2014 Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]	Dec. 31, 2014 Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]	Dec. 31, 2013 Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]	Mar. 14, 2013 Senior Notes, 3.875% Due 2023 [Member]	Dec. 31, 2014 Senior Notes, 3.875% Due 2023 [Member]	Dec. 31, 2013 Senior Notes, 3.875% Due 2023 [Member]	Nov. 27, 2012 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2013 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes, 4.95% Due 2022 [Member]	Dec. 31, 2013 Senior Notes, 4.95% Due 2022 [Member]	Dec. 31, 2014 Senior Notes, 3.25% Due 2015 [Member]	Dec. 31, 2013 Senior Notes, 3.25% Due 2015 [Member]	Dec. 31, 2014 Eagle Ford System [Member]	Mar. 31, 2013 Eagle Ford System [Member]	Mar. 14, 2013 Eagle Ford System [Member]	Nov. 30, 2012 Eagle Ford System [Member]	Nov. 02, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Eagle Ford System [Member] Senior Notes, 3.875% Due 2023 [Member]	Mar. 31, 2012 Southeast Texas [Member]	Mar. 13, 2012 Southeast Texas [Member]	Dec. 31, 2014 Amended and Restated Credit Agreement [Member]	Dec. 31, 2014 Commercial Paper [Member]	Dec. 31, 2013 Commercial Paper [Member]	Dec. 31, 2014 Credit Agreement [Member]	Dec. 31, 2014 London Interbank Offered Rate (LIBOR) [Member] Credit Agreement [Member]	Dec. 31, 2014 Federal Funds Effective Swap Rate [Member] Credit Agreement [Member]	Dec. 31, 2014 London Interbank Offered Rate (LIBOR) Market Index [Member] Credit Agreement [Member]	Dec. 31, 2013 Credit Agreement [Member]	Dec. 31, 2014 Credit Agreement [Member]	Dec. 31, 2014 Minimum [Member] Credit Agreement [Member]	Dec. 31, 2014 Maximum [Member] Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity																												$ 1,000,000,000			$ 1,000,000,000
Short-term borrowings	0	335,000,000																											0	335,000,000
Line of credit facility, maturity date																															Nov. 10, 2016
Letters of credit issued																																			1,000,000
Letters of credit outstanding																																			1,000,000	1,100,000
Unused capacity under the credit agreement																															1,249,000,000
Variable rate basis spread																																1.275%	0.50%	1.00%
Basis spread determined by credit rating																															0.275%
Commitment fee percentage																															0.23%
Maximum leverage ratio																																					5.0	1.0
Temporary maximum leverage ratio post-acquisition																																					5.5	1.0
Senior notes issued					325,000,000	0		400,000,000	0	500,000,000	500,000,000	500,000,000		500,000,000	500,000,000	350,000,000	350,000,000	250,000,000	250,000,000
Equity Method Investment, Ownership Percentage																								33.33%
Senior notes interest rate percentage					2.70%			5.60%		3.875%	3.875%		2.50%	2.50%		4.95%		3.25%
Term of outstanding debt										10 years			5 years
Maturity date											Mar. 15, 2023			Dec. 01, 2017		Apr. 01, 2022		Oct. 01, 2015
Proceeds from long-term debt	$ 719,000,000	$ 1,957,000,000	$ 2,665,000,000	$ 320,000,000			$ 392,000,000			$ 490,000,000
Business Acquisition, Percentage of Voting Interests Acquired																				20.00%	46.67%	46.67%	33.33%		46.67%	66.67%	66.67%
First payment date											Sep. 15, 2013

Debt - Future Maturities of Long-Term Debt (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Maturities of Long-term Debt [Abstract]
2014	$ 250
2015	0
2016	500
2017	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	325
Thereafter	1,250
Total principal	2,325
Unamortized discount	(14)	(10)
Total	$ 2,311	$ 1,925

Risk Management and Hedging Activities - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended						12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2012	Feb. 29, 2012	Dec. 31, 2013 Interest Rate Swap [Member] Minimum [Member]	Dec. 31, 2013 Interest Rate Swap [Member] Maximum [Member]	Dec. 31, 2014 Commodity Derivatives [Member]	Dec. 31, 2013 Commodity Derivatives [Member]	Dec. 31, 2014 Interest Rate Swap [Member]	Dec. 31, 2014 Cash Flow Hedge [Member]	Dec. 31, 2013 Cash Flow Hedge [Member]	Dec. 31, 2012 Cash Flow Hedge [Member]	Dec. 31, 2014 Cash Flow Hedge [Member] Commodity Derivatives [Member]	Dec. 31, 2013 Cash Flow Hedge [Member] Commodity Derivatives [Member]	Dec. 31, 2012 Cash Flow Hedge [Member] Commodity Derivatives [Member]	Dec. 31, 2014 Cash Flow Hedge [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Cash Flow Hedge [Member] Interest Rate Swap [Member]	Dec. 31, 2012 Cash Flow Hedge [Member] Interest Rate Swap [Member]	Dec. 31, 2014 Limited Partner [Member]	Dec. 31, 2013 Limited Partner [Member]	Aug. 31, 2013 Limited Partner [Member]	Dec. 31, 2014 Senior Notes, 4.95% Due 2022 [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net							$ (1)	$ 1
Accumulated other comprehensive loss	(9)	(11)								(9)	(11)	(15)	(6)	(6)	(6)	(4)	(6)	(10)
Notional value of derivative	150	150			70	80
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	113,949,868	89,045,139	5,148,500	30,701															14,375,000	12,650,000	9,000,000
Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring								$ 1	$ 1
Debt Instrument, Interest Rate, Stated Percentage																						4.95%

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) (USD $)
In Millions, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

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

$ 269

$ 166

Amounts Not Offset in the Balance Sheet - Financial Instruments

(42)

^[1]

(13)

^[1]

Net Amount, Assets

227

153

Gross Amounts of Liabilities Presented in the Balance Sheet

(43)

(27)

Amounts Not Offset in the Balance Sheet - Financial Instruments

^[1]

Net Amount, Liabilities

Interest rate derivative [Member]

Fair Values Of Financial Assets And Liabilities Including Derivative Financial Instruments [Line Items]

Gross Amounts of Liabilities Presented in the Balance Sheet

(2)

Amounts Not Offset in the Balance Sheet - Financial Instruments

^[1]

Net Amount, Liabilities

$ 0

$ 2

[1]	There is no cash collateral pledged or received against these positions.

- Definition

Fair value, after offset of derivative liability, of financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, before offset against an obligation to return collateral under a master netting arrangement. Includes assets elected not to be offset. Excludes assets not subject to a master netting arrangement.

+ References+ Details

- Definition

Fair value, after offset of derivative asset, of financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, elected not to be and before offset against a right to receive collateral under a master netting arrangement. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References+ Details

Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	$ 230	$ 79
Unrealized gains on derivative instruments - long-term	39	87
Derivative Liability [Abstract]
Unrealized losses on derivative instruments - long-term	0	(1)
Commodity Derivatives [Member] \| Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	230	79
Unrealized gains on derivative instruments - long-term	39	87
Derivative assets, fair value, total	269	166
Commodity Derivatives [Member] \| Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	43	26
Unrealized losses on derivative instruments - long-term	0	(1)
Derivative liabilities, fair value, total	(43)	(27)
Interest Rate Derivatives [Member] \| Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	0	0
Unrealized gains on derivative instruments - long-term	0	0
Derivative assets, fair value, total	0	0
Interest Rate Derivatives [Member] \| Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	0	2
Unrealized losses on derivative instruments - long-term	0	0
Derivative liabilities, fair value, total	$ 0	$ (2)

- Definition

Fair value of liability arising from contracts that meet the criteria of being accounted for as derivative instruments, financial instrument or contract used to mitigate a specified risk (hedge), energy marketing activities (trading activities), expected to be settled after one year or beyond the normal operating cycle, if longer. Examples of energy marketing activities include, but are not limited to, trading of electricity, coal, natural gas and oil using financial instruments, including, but not limited to, forward contracts, options and swaps.

+ References+ Details

Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Net deferred losses in AOCI (ending balance)

$ (9)

$ (11)

Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Net deferred (losses) gains in AOCI (beginning balance)

(11)

(15)

Gains (losses) recognized in AOCI on derivatives - effective portion

Net deferred losses in AOCI (ending balance)

(9)

(11)

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)

(6)

(10)

Gains (losses) recognized in AOCI on derivatives - effective portion

^[1]

Net deferred losses in AOCI (ending balance)

(4)

(6)

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)

Gains (losses) recognized in AOCI on derivatives - effective portion

Net deferred losses in AOCI (ending balance)

(6)

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

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)

^[2]

Gains (losses) recognized in AOCI on derivatives - effective portion

^[2]

Net deferred losses in AOCI (ending balance)

^[2]

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

$ 0

^[2]

[1]	Included in interest expense in our consolidated statements of operations.
[2]	Relates to Discovery, our unconsolidated affiliate.

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References+ Details

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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	(1)
Gain/Loss Reclassified From AOCI to Earnings-Discontinuance		$ 1

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Derivative [Line Items]

Accumulated other comprehensive loss

$ (9)

$ (11)

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

(9)

(11)

(15)

Losses Reclassified From AOCI to Earnings-Effective Portion

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

(4)

(6)

(10)

Losses Reclassified From AOCI to Earnings-Effective Portion

^[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)

Losses Reclassified From AOCI to Earnings-Effective Portion

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

Cash Flow Hedge [Member] | Foreign Currency Derivatives [Member]

Derivative [Line Items]

Accumulated other comprehensive loss

^[2]

Losses Reclassified From AOCI to Earnings-Effective Portion

^[2]

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

$ 0

^[2]

[1]	Included in interest expense in our consolidated statements of operations.
[2]	Relates to Discovery, our unconsolidated affiliate.

- Definition

+ References+ Details

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 $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Affiliates [Member] \| Commodity Derivatives [Member]
Derivative [Line Items]
Realized	$ 70	$ 73	$ 45
Unrealized	48	(51)	8
(Losses) gains from commodity derivative activity, net	118	22	53
Third Party [Member] \| Commodity Derivatives [Member]
Derivative [Line Items]
Realized	(2)	(19)	4
Unrealized	38	14	13
(Losses) gains from commodity derivative activity, net	36	(5)	17
Third Party [Member] \| Interest Rate Derivatives [Member]
Derivative [Line Items]
Realized	(2)	(2)	(7)
Unrealized	$ 2	$ 2	$ 7

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	12 Months Ended
	Dec. 31, 2014 bbl	Dec. 31, 2013 bbl
Crude Oil [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013		(690,945)
Net (Short) Position (Bbls), 2014	(745,695)	(745,695)
Net (Short) Position (Bbls), 2015	(561,922)	(561,922)
Net (Short) Position (Bbls), 2016	0
Natural Gas [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013		(21,673,620)
Net Long (Short) Position (MMBtu), 2014	(20,803,975)	(9,458,975)
Net Long (Short) Position (MMBtu), 2015	(5,668,564)	(1,838,564)
Net Long (Short) Position (MMBtu), 2016	(6,387,500)
Natural Gas Liquids [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013		5,171,910
Net (Short) Position (Bbls), 2014	(5,573,570)	(5,691,570)
Net (Short) Position (Bbls), 2015	(813,267)	(813,267)
Net (Short) Position (Bbls), 2016	0
Natural Gas Basis Swaps [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013		21,415,000
Net Long (Short) Position (MMBtu), 2014	2,640,000	1,875,000
Net Long (Short) Position (MMBtu), 2015	1,690,000	0
Net Long (Short) Position (MMBtu), 2016	0

Partnership Equity and Distributions - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended					12 Months Ended				0 Months Ended			1 Months Ended					1 Months Ended			1 Months Ended	12 Months Ended				3 Months Ended	12 Months Ended						3 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Feb. 29, 2012	Dec. 31, 2014 Distribution Stage First [Member]	Dec. 31, 2014 Distribution Stage Second [Member]	Dec. 31, 2014 Distribution Stage Third [Member]	Dec. 31, 2014 Distribution Stage Thereafter [Member]	Nov. 27, 2012 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Senior Notes, 2.50% Due 2017 [Member]	Dec. 31, 2014 Sand Hills Pipeline [Member]	Mar. 31, 2013 Eagle Ford System [Member]	Nov. 30, 2012 Eagle Ford System [Member]	Dec. 31, 2014 Eagle Ford System [Member]	Mar. 14, 2013 Eagle Ford System [Member]	Nov. 02, 2012 Eagle Ford System [Member]	Jul. 31, 2012 Mont Belvieu Fractionators [Member]	Mar. 31, 2012 Southeast Texas [Member]	Mar. 13, 2012 Southeast Texas [Member]	Jan. 31, 2012 East Texas System [Member]	Dec. 31, 2014 General Partner [Member]	Dec. 31, 2014 2014 Equity Distribution Agreement [Member]	Dec. 31, 2013 Equity Distribution Agreement [Member]	Dec. 31, 2014 Equity Distribution Agreement [Member]	Dec. 31, 2013 2011 Equity Distribution Agreement [Member]	Dec. 31, 2013 2011 Equity Distribution Agreement [Member]	Dec. 31, 2012 2011 Equity Distribution Agreement [Member]	Dec. 31, 2014 Limited Partners [Member]	Dec. 31, 2013 Limited Partners [Member]	Dec. 31, 2012 Limited Partners [Member]	Aug. 31, 2013 Limited Partners [Member]	Dec. 31, 2014 2013 Equity Distribution Agreement [Member]	Dec. 31, 2014 2013 Equity Distribution Agreement [Member]	Dec. 31, 2013 2013 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued		113,949,868	89,045,139		5,148,500	30,701																		2,256,066	1,839,430					14,375,000	12,650,000		9,000,000	3,769,635	3,769,635
Proceeds from issuance of common stock																								$ 119	$ 87		$ 67	$ 67	$ 47					$ 0	$ 206
Offering costs																								1	1		2	2	2					0	2
Maximum aggregate offering amount																								500					150							300
Issuance of common units			24,897,977	11,285,956																								1,408,547	1,147,654	20,407,571	24,897,977	11,285,956
Price per common unit					$ 47.42																									$ 48.9	$ 40.63		$ 50.04
Net proceeds					234																									677	494		434
Offer value of common stock remaining available for sale																										380
Consideration financed through issuance of common units														2,789,739	1,912,663				1,536,098	1,000,417		727,520								4,497,158
Equity Method Investment, Ownership Percentage													33.33%					33.33%
Business Acquisition, Percentage of Voting Interests Acquired														46.67%	33.33%	20.00%	46.67%			66.67%	66.67%	49.90%
Senior notes interest rate percentage											2.50%	2.50%
Term of outstanding debt											5 years
Partnership deadline for distributions (in days)		45 days
General partner ownership interest																							0.00%
Limited partner ownership interest																							2.00%
Distribution unitholders and general partner per unit							$ 0.4025	$ 0.437	$ 0.525
Minimum distribution level percentage								13.00%	23.00%	48.00%
Partners' Capital Account, Units, Sold in Private Placement	4,989,802
Units Sold Under Private Placement Price Per Unit	$ 35.55
Proceeds from Issuance of Private Placement	$ 174

Partnership Equity and Distributions - Cash Distribution (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partnership Equity And Distribution [Line Items]
Total Cash Distribution (Millions)	$ 420	$ 277	$ 181
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	$ 0.7575
Total Cash Distribution (Millions)	111
May Fifteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.745
Total Cash Distribution (Millions)	106
February Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7325
Total Cash Distribution (Millions)	86
November 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.72
Total Cash Distribution (Millions)	82
August 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.71
Total Cash Distribution (Millions)	72
May 15, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7
Total Cash Distribution (Millions)	69
February 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.69
Total Cash Distribution (Millions)	54
November 14, 2012 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.68
Total Cash Distribution (Millions)	53
August 14, 2012 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.67
Total Cash Distribution (Millions)	49
May 15, 2012 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.66
Total Cash Distribution (Millions)	43
February 14, 2012 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.65
Total Cash Distribution (Millions)	$ 37

Equity-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	850,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	$ 1
Allocated Share-based Compensation Expense	$ 1	$ 2	$ 2

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
State Gross Margin Tax Rate	0.95%	0.975%	1.00%
Current State and Local Tax Expense (Benefit)	3	3	1
Deferred State and Local Income Tax Expense (Benefit)	3	5	0
Income tax expense	6	8	1
Deferred Tax Liabilities, Net, Noncurrent	$ 13	$ 11

- Definition

Amount of current federal tax expense (benefit) pertaining to income (loss) from continuing operations.

+ References+ Details

- Definition

Amount of current state and local tax expense (benefit) pertaining to income (loss) from continuing operations.

+ References+ Details

- Definition

Amount of deferred state and local tax expense (benefit) pertaining to income (loss) from continuing operations.

+ References+ Details

Business Segments - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Segment

Project

Dec. 31, 2013

Project

Dec. 31, 2012

Segment Reporting Information [Line Items]

Total operating revenues

$ 881

$ 868

$ 812

$ 1,081

$ 821

$ 689

$ 792

$ 749

$ 3,642

$ 3,051

$ 2,824

Number of reporting segments

Ownership interest percentage

100.00%

Number of owned and operated rail terminals

Number of owned marine import terminals

Number of leased marine terminals

Pipeline Terminals

Gross margin

847

625

^[1]

609

Other Cost and Expense, Operating

(216)

(215)

(197)

Depreciation, Depletion and Amortization, Nonproduction

(110)

(95)

(91)

General and Administrative Expense

(64)

(63)

(75)

Earnings from unconsolidated affiliates

Interest expense

(86)

(52)

(42)

Income tax expense

(6)

(8)

(1)

Net income

203

116

111

437

217

229

Net income attributable to noncontrolling interests

(4)

(10)

(7)

(3)

(4)

(3)

(14)

(17)

(13)

Net Income (Loss) Attributable to Parent

199

116

107

423

200

216

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(36)

Capital expenditures

338

363

484

Acquisition expenditures

775

782

745

Investments in unconsolidated affiliates

151

242

158

Natural Gas Services [Member]

Segment Reporting Information [Line Items]

Total operating revenues

3,163

2,598

2,345

Gross margin

756

501

503

Other Cost and Expense, Operating

(189)

(184)

(166)

Depreciation, Depletion and Amortization, Nonproduction

(101)

(87)

(83)

General and Administrative Expense

Earnings from unconsolidated affiliates

Interest expense

Income tax expense

Net income

469

230

(269)

Net income attributable to noncontrolling interests

(14)

(17)

(13)

Net Income (Loss) Attributable to Parent

455

213

256

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(36)

Capital expenditures

297

334

468

Acquisition expenditures

102

696

715

Investments in unconsolidated affiliates

133

115

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%

Front Range Pipeline [Member]

Segment Reporting Information [Line Items]

Equity Method Investment, Ownership Percentage

33.33%

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

Gross margin

Other Cost and Expense, Operating

(16)

Depreciation, Depletion and Amortization, Nonproduction

(7)

(6)

General and Administrative Expense

Earnings from unconsolidated affiliates

Interest expense

Income tax expense

Net income

119

(53)

Net income attributable to noncontrolling interests

Net Income (Loss) Attributable to Parent

119

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

Capital expenditures

Acquisition expenditures

673

Investments in unconsolidated affiliates

109

Wholesale Propane Logistics [Member]

Segment Reporting Information [Line Items]

Total operating revenues

406

380

415

Gross margin

Other Cost and Expense, Operating

(11)

(15)

Depreciation, Depletion and Amortization, Nonproduction

(2)

General and Administrative Expense

Earnings from unconsolidated affiliates

Interest expense

Income tax expense

Net income

(25)

Net income attributable to noncontrolling interests

Net Income (Loss) Attributable to Parent

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(3)

(1)

Capital expenditures

Acquisition expenditures

Investments in unconsolidated affiliates

Other [Member]

Segment Reporting Information [Line Items]

Total operating revenues

Gross margin

^[1]

Other Cost and Expense, Operating

Depreciation, Depletion and Amortization, Nonproduction

General and Administrative Expense

(64)

(63)

(75)

Earnings from unconsolidated affiliates

Interest expense

(86)

(52)

(42)

Income tax expense

(6)

(8)

(1)

Net income

(156)

(123)

118

Net income attributable to noncontrolling interests

Net Income (Loss) Attributable to Parent

(156)

(123)

(118)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

Capital expenditures

Acquisition expenditures

Investments in unconsolidated affiliates

$ 0

[1]

Business Segments - Segment Information (Detail) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Segment Reporting Information [Line Items]

Total operating revenues

$ 881

$ 868

$ 812

$ 1,081

$ 821

$ 689

$ 792

$ 749

$ 3,642

$ 3,051

$ 2,824

Gross margin

847

625

^[1]

609

Operating and maintenance expense

(216)

(215)

(197)

Depreciation and amortization expense

(110)

(95)

(91)

General and administrative expense

(64)

(63)

(75)

Other expense

(3)

Earnings from unconsolidated affiliates

Other operating income

Interest expense

(86)

(52)

(42)

Income tax expense

(6)

(8)

(1)

Net income

203

116

111

437

217

229

Net income attributable to noncontrolling interests

(4)

(10)

(7)

(3)

(4)

(3)

(14)

(17)

(13)

Net income attributable to partners

199

116

107

423

200

216

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(36)

Non-cash lower of cost or market adjustments

Capital expenditures

338

363

484

Acquisition expenditures

775

782

745

Investments in unconsolidated affiliates

151

242

158

Total long-term assets

5,149

4,064

5,149

4,064

Current assets

590

503

590

503

Total assets

5,739

4,567

5,739

4,567

Natural Gas Services [Member]

Segment Reporting Information [Line Items]

Total operating revenues

3,163

2,598

2,345

Gross margin

756

501

503

Operating and maintenance expense

(189)

(184)

(166)

Depreciation and amortization expense

(101)

(87)

(83)

General and administrative expense

Other expense

(2)

Earnings from unconsolidated affiliates

Other operating income

(1)

Interest expense

Income tax expense

Net income

469

230

(269)

Net income attributable to noncontrolling interests

(14)

(17)

(13)

Net income attributable to partners

455

213

256

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(36)

Non-cash lower of cost or market adjustments

Capital expenditures

297

334

468

Acquisition expenditures

102

696

715

Investments in unconsolidated affiliates

133

115

Total long-term assets

3,609

3,303

3,609

3,303

NGL Logistics [Member]

Segment Reporting Information [Line Items]

Total operating revenues

Gross margin

Operating and maintenance expense

(16)

Depreciation and amortization expense

(7)

(6)

General and administrative expense

Other expense

(1)

Earnings from unconsolidated affiliates

Other operating income

Interest expense

Income tax expense

Net income

119

(53)

Net income attributable to noncontrolling interests

Net income attributable to partners

119

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

Non-cash lower of cost or market adjustments

Capital expenditures

Acquisition expenditures

673

Investments in unconsolidated affiliates

109

Total long-term assets

1,364

555

1,364

555

Wholesale Propane Logistics [Member]

Segment Reporting Information [Line Items]

Total operating revenues

406

380

415

Gross margin

Operating and maintenance expense

(11)

(15)

Depreciation and amortization expense

(2)

General and administrative expense

Other expense

Earnings from unconsolidated affiliates

Other operating income

Interest expense

Income tax expense

Net income

(25)

Net income attributable to noncontrolling interests

Net income attributable to partners

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(3)

(1)

Non-cash lower of cost or market adjustments

Capital expenditures

Acquisition expenditures

Investments in unconsolidated affiliates

Total long-term assets

118

106

118

106

Other [Member]

Segment Reporting Information [Line Items]

Total operating revenues

Gross margin

^[1]

Operating and maintenance expense

Depreciation and amortization expense

General and administrative expense

(64)

(63)

(75)

Other expense

Earnings from unconsolidated affiliates

Other operating income

Interest expense

(86)

(52)

(42)

Income tax expense

(6)

(8)

(1)

Net income

(156)

(123)

118

Net income attributable to noncontrolling interests

Net income attributable to partners

(156)

(123)

(118)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

Non-cash lower of cost or market adjustments

Capital expenditures

Acquisition expenditures

Investments in unconsolidated affiliates

Total long-term assets

$ 58

$ 100

$ 58

$ 100

[1]

Business Segments - Segment Information (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014 Project	Dec. 31, 2013 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
Affiliated Entity [Member] \| Eagle Ford System [Member]
Segment Reporting Information [Line Items]
Ownership interest percentage	80.00%

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$ 73	$ 40	$ 23
Cash paid for income taxes, net of income tax refunds	2	1	1
Property, plant and equipment acquired with accounts payable	43	27	47
Other non-cash additions of property, plant and equipment	4	1	8
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	65	0	0
Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	160	125	0
Noncash Investing and Financing Activities Related Text	0	1	0
Non-Cash Change in Advances To Predecessor	$ 0	$ 0	$ (115)

Quarterly Financial Data (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 881	$ 868	$ 812	$ 1,081	$ 821	$ 689	$ 792	$ 749	$ 3,642	$ 3,051	$ 2,824
Operating Income (Loss)	198	111	37	108	48	14	117	65	454	244	246
Net income	203	116	29	89	40	6	111	60	437	217	229
Net income attributable to noncontrolling interests	(4)	0	0	(10)	(7)	(3)	(4)	(3)	(14)	(17)	(13)
Net Income (Loss) Attributable to Parent	199	116	29	79	33	3	107	57	423	200	216
Net Income (Loss) Allocated to Limited Partners	$ 168	$ 86	$ 2	$ 47	$ 8	$ (20)	$ 86	$ 31	$ 303	$ 105	$ 124
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 1.48	$ 0.77	$ 0.02	$ 0.50	$ 0.09	$ (0.24)	$ 1.11	$ 0.48	$ 2.84	$ 1.34	$ 2.28

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References+ Details

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ASSETS
Cash and cash equivalents	$ 25	$ 12	$ 2	$ 8
Accounts receivable, net	270	342
Inventories	63	67
Other	232	82
Total current assets	590	503
Property, plant and equipment, net	3,347	3,046
Goodwill and intangible assets, net	274	283
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,459	627
Other long-term assets	69	108
Total assets	5,739	4,567
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	601	723
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,061	1,590
Other long-term liabilities	51	41
Total liabilities	2,713	2,354
Commitments and contingent liabilities
Equity:
Predecessor equity		40
Net equity	3,002	1,956
Accumulated other comprehensive loss	(9)	(11)
Total partners' equity	2,993	1,985
Noncontrolling interests	33	228
Total equity	3,026	2,213	1,636	1,605
Total liabilities and equity	5,739	4,567
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	2,610	1,805
Investments in consolidated subsidiaries	383	181
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	2,993	1,986
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	1
Advances payable - consolidated subsidiaries	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	0	1
Commitments and contingent liabilities
Equity:
Predecessor equity		0
Net equity	2,993	1,985
Accumulated other comprehensive loss	0	0
Total partners' equity	2,993	1,985
Noncontrolling interests	0	0
Total equity	2,993	1,985
Total liabilities and equity	2,993	1,986
Subsidiary Issuer [Member]
ASSETS
Cash and cash equivalents	24	0	3	4
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	24	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	1,962	1,683
Investments in consolidated subsidiaries	712	426
Investments in unconsolidated affiliates	0	0
Other long-term assets	17	12
Total assets	2,715	2,121
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	271	350
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,061	1,590
Other long-term liabilities	0	0
Total liabilities	2,332	1,940
Commitments and contingent liabilities
Equity:
Predecessor equity		0
Net equity	387	187
Accumulated other comprehensive loss	(4)	(6)
Total partners' equity	383	181
Noncontrolling interests	0	0
Total equity	383	181
Total liabilities and equity	2,715	2,121
Non-Guarantor Subsidiaries [Member]
ASSETS
Cash and cash equivalents	1	12	2	6
Accounts receivable, net	270	342
Inventories	63	67
Other	232	82
Total current assets	566	503
Property, plant and equipment, net	3,347	3,046
Goodwill and intangible assets, net	274	283
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,459	627
Other long-term assets	52	96
Total assets	5,698	4,555
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	330	372
Advances payable - consolidated subsidiaries	4,572	3,488
Long-term debt	0	0
Other long-term liabilities	51	41
Total liabilities	4,953	3,901
Commitments and contingent liabilities
Equity:
Predecessor equity		40
Net equity	717	391
Accumulated other comprehensive loss	(5)	(5)
Total partners' equity	712	426
Noncontrolling interests	33	228
Total equity	745	654
Total liabilities and equity	5,698	4,555
Consolidating Adjustments [Member]
ASSETS
Cash and cash equivalents	0	0	(3)	(2)
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	(4,572)	(3,488)
Investments in consolidated subsidiaries	(1,095)	(607)
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	(5,667)	(4,095)
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Advances payable - consolidated subsidiaries	(4,572)	(3,488)
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	(4,572)	(3,488)
Commitments and contingent liabilities
Equity:
Predecessor equity		0
Net equity	(1,095)	(607)
Accumulated other comprehensive loss	0	0
Total partners' equity	(1,095)	(607)
Noncontrolling interests	0	0
Total equity	(1,095)	(607)
Total liabilities and equity	$ (5,667)	$ (4,095)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									$ 3,143	$ 2,763	$ 2,520
Transportation, processing and other									345	271	234
Gain (Loss) on Derivative Instruments, Net, Pretax									154	17	70
Total operating revenues	881	868	812	1,081	821	689	792	749	3,642	3,051	2,824
Purchases of natural gas, propane and NGLs									2,795	2,426	2,215
Operating and maintenance expense									216	215	197
Depreciation and amortization expense									110	95	91
General and administrative expense									64	63	75
Other expense (income)									3	8	0
Total operating costs and expenses									3,188	2,807	2,578
Operating Income (Loss)	198	111	37	108	48	14	117	65	454	244	246
Interest expense									(86)	(52)	(42)
Income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									75	33	26
Income before income taxes									443	225	230
Income tax expense									(6)	(8)	(1)
Net income	203	116	29	89	40	6	111	60	437	217	229
Net income attributable to noncontrolling interests	(4)	0	0	(10)	(7)	(3)	(4)	(3)	(14)	(17)	(13)
Net income attributable to partners	199	116	29	79	33	3	107	57	423	200	216
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Other expense (income)									0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest expense									0	0	0
Income from consolidated subsidiaries									423	200	216
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									423	200	216
Income tax expense									0	0	0
Net income									423	200	216
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									423	200	216
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Other expense (income)									0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest expense									(86)	(52)	(41)
Income from consolidated subsidiaries									509	252	257
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									423	200	216
Income tax expense									0	0	0
Net income									423	200	216
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									423	200	216
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									3,143	2,763	2,520
Transportation, processing and other									345	271	234
Gain (Loss) on Derivative Instruments, Net, Pretax									154	17	70
Total operating revenues									3,642	3,051	2,824
Purchases of natural gas, propane and NGLs									2,795	2,426	2,215
Operating and maintenance expense									216	215	197
Depreciation and amortization expense									110	95	91
General and administrative expense									64	63	75
Other expense (income)									3	8
Total operating costs and expenses									3,188	2,807	2,578
Operating Income (Loss)									454	244	246
Interest expense									0	0	(1)
Income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									75	33	26
Income before income taxes									529	277	271
Income tax expense									(6)	(8)	(1)
Net income									523	269	270
Net income attributable to noncontrolling interests									(14)	(17)	(13)
Net income attributable to partners									509	252	257
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Other expense (income)									0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest expense									0	0	0
Income from consolidated subsidiaries									(932)	(452)	(473)
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									(932)	(452)	(473)
Income tax expense									0	0	0
Net income									(932)	(452)	(473)
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									$ (932)	$ (452)	$ (473)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net income	$ 203	$ 116	$ 29	$ 89	$ 40	$ 6	$ 111	$ 60	$ 437	$ 217	$ 229
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									2	4	10
Other comprehensive income from consolidated subsidiaries									0	0	0
Net unrealized losses on cash flow hedges											(1)
Total other comprehensive income									2	4	9
Total comprehensive income									439	221	238
Total comprehensive income (loss) attributable to noncontrolling interests									(14)	(17)	(13)
Total comprehensive income attributable to partners									425	204	225
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									423	200	216
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									2	4	9
Total other comprehensive income									2	4	9
Total comprehensive income									425	204	225
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									425	204	225
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									423	200	216
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									2	4	10
Other comprehensive income from consolidated subsidiaries									0	0	0
Net unrealized losses on cash flow hedges											(1)
Total other comprehensive income									2	4	9
Total comprehensive income									425	204	225
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									425	204	225
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									523	269	270
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									0	0	0
Total comprehensive income									523	269	270
Total comprehensive income (loss) attributable to noncontrolling interests									(14)	(17)	(13)
Total comprehensive income attributable to partners									509	252	257
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									(932)	(452)	(473)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									(2)	(4)	(9)
Total other comprehensive income									(2)	(4)	(9)
Total comprehensive income									(934)	(456)	(482)
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									$ (934)	$ (456)	$ (482)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$ 524	$ 345	$ 102
Payments for (Proceeds from) Other Investing Activities	0	0	0
INVESTING ACTIVITIES:
Capital expenditures	(338)	(363)	(484)
Acquisitions, net of cash acquired	(102)	(696)	(433)
Payments to Acquire Equity Method Investments	(673)	(86)
Acquisition of unconsolidated affiliates	(673)	(86)	(312)
Proceeds from sales of assets	28	0	2
Net cash used in investing activities	(1,236)	(1,387)	(1,384)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	719	1,957	2,665
Payments of long-term debt	0	(1,988)	(1,792)
(Payments) proceeds of commercial paper, net	(335)	335	0
Payments of deferred financing costs	(7)	(4)	(8)
Excess purchase price over acquired net assets and commodity hedge	(18)	(85)	(225)
Proceeds from issuance of common units, net of offering cost	1,001	1,083	455
Net change in advances to predecessor from DCP Midstream, LLC	(6)	11	336
Payments of Ordinary Dividends	(420)	(277)	(181)
Distributions to noncontrolling interests	(14)	(24)	(9)
Payments to Noncontrolling Interests	(198)	0	0
Contributions from noncontrolling interests	3	46	25
Payments of Capital Distribution	420	277	181
Payments Of Distributions To Parent	0	3	0
Contributions from DCP Midstream, LLC	0	1	10
Net cash provided by financing activities	725	1,052	1,276
Net change in cash and cash equivalents	13	10	(6)
Cash and cash equivalents, beginning of period	12	2	8
Cash and cash equivalents, end of period	25	12	2
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			(745)
Investments in unconsolidated affiliates	(151)	(242)	(158)
Return of investment from unconsolidated affiliate	0	0	1
Parent Guarantor [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0	0
Payments for (Proceeds from) Other Investing Activities	(581)	(806)	(274)
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Acquisitions, net of cash acquired	0	0
Payments to Acquire Equity Method Investments	0	0
Acquisition of unconsolidated affiliates	0	0
Proceeds from sales of assets	0		0
Net cash used in investing activities	(581)	(806)	(274)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Payments of long-term debt		0	0
(Payments) proceeds of commercial paper, net	0
Payments of deferred financing costs	0	0	0
Excess purchase price over acquired net assets and commodity hedge	0	0	0
Proceeds from issuance of common units, net of offering cost	1,001	1,083	455
Net change in advances to predecessor from DCP Midstream, LLC	0	0	0
Payments of Ordinary Dividends	(420)	(277)	(181)
Distributions to noncontrolling interests	0	0	0
Payments to Noncontrolling Interests	0
Contributions from noncontrolling interests	0	0	0
Payments of Capital Distribution		0
Contributions from DCP Midstream, LLC		0	0
Net cash provided by financing activities	581	806	274
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Investments in unconsolidated affiliates			0
Return of investment from unconsolidated affiliate			0
Subsidiary Issuer [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	(73)	(45)	(39)
Payments for (Proceeds from) Other Investing Activities	(280)	(258)	(827)
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Acquisitions, net of cash acquired	0	0
Payments to Acquire Equity Method Investments	0	0
Acquisition of unconsolidated affiliates	0	0
Proceeds from sales of assets	0		0
Net cash used in investing activities	(280)	(258)	(827)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	719	1,957	2,665
Payments of long-term debt		(1,988)	(1,792)
(Payments) proceeds of commercial paper, net	(335)
Payments of deferred financing costs	(7)	(4)	(8)
Excess purchase price over acquired net assets and commodity hedge	0	0	0
Proceeds from issuance of common units, net of offering cost	0	0	0
Net change in advances to predecessor from DCP Midstream, LLC	0	0	0
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	0	0	0
Payments to Noncontrolling Interests	0
Contributions from noncontrolling interests	0	0	0
Payments of Capital Distribution		0
Contributions from DCP Midstream, LLC		0	0
Net cash provided by financing activities	377	300	865
Net change in cash and cash equivalents	24	(3)	(1)
Cash and cash equivalents, beginning of period	0	3	4
Cash and cash equivalents, end of period	24	0	3
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Investments in unconsolidated affiliates			0
Return of investment from unconsolidated affiliate			0
Non-Guarantor Subsidiaries [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	597	387	142
Payments for (Proceeds from) Other Investing Activities	0	0	0
INVESTING ACTIVITIES:
Capital expenditures	(338)	(363)	(484)
Acquisitions, net of cash acquired	(102)	(696)
Payments to Acquire Equity Method Investments	(673)	(86)
Acquisition of unconsolidated affiliates	(151)	(242)
Proceeds from sales of assets	28		2
Net cash used in investing activities	(1,236)	(1,387)	(1,384)
Proceeds from (Payments for) Other Financing Activities	861	1,064	1,101
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Payments of long-term debt		0	0
(Payments) proceeds of commercial paper, net	0
Payments of deferred financing costs	0	0	0
Excess purchase price over acquired net assets and commodity hedge	(18)	(85)	(225)
Proceeds from issuance of common units, net of offering cost	0	0	0
Net change in advances to predecessor from DCP Midstream, LLC	(6)	11	336
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	(14)	(24)	(9)
Payments to Noncontrolling Interests	(198)
Contributions from noncontrolling interests	3	46	25
Payments of Capital Distribution		3
Contributions from DCP Midstream, LLC		1	10
Net cash provided by financing activities	628	1,010	1,238
Net change in cash and cash equivalents	(11)	10	(4)
Cash and cash equivalents, beginning of period	12	2	6
Cash and cash equivalents, end of period	1	12	2
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			(745)
Investments in unconsolidated affiliates			(158)
Return of investment from unconsolidated affiliate			1
Consolidating Adjustments [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	3	(1)
Payments for (Proceeds from) Other Investing Activities	861	1,064	1,101
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Acquisitions, net of cash acquired	0	0
Payments to Acquire Equity Method Investments	0	0
Acquisition of unconsolidated affiliates	0	0
Proceeds from sales of assets	0		0
Net cash used in investing activities	861	1,064	1,101
Proceeds from (Payments for) Other Financing Activities	(861)	(1,064)	(1,101)
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Payments of long-term debt		0	0
(Payments) proceeds of commercial paper, net	0
Payments of deferred financing costs	0	0	0
Excess purchase price over acquired net assets and commodity hedge	0	0	0
Proceeds from issuance of common units, net of offering cost	0	0	0
Net change in advances to predecessor from DCP Midstream, LLC	0	0	0
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	0	0	0
Payments to Noncontrolling Interests	0
Contributions from noncontrolling interests	0	0	0
Payments of Capital Distribution		0
Contributions from DCP Midstream, LLC		0	0
Net cash provided by financing activities	(861)	(1,064)	(1,101)
Net change in cash and cash equivalents	0	3	(1)
Cash and cash equivalents, beginning of period	0	(3)	(2)
Cash and cash equivalents, end of period	0	0	(3)
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Investments in unconsolidated affiliates			0
Return of investment from unconsolidated affiliate			$ 0

Valuation and Qualifying Accounts and Reserves (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance	$ 3	$ 3	$ 4
Valuation Allowances and Reserves, Charged to Cost and Expense	1	1	0
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	(1)	(1)	(1)
Valuation Allowances and Reserves, Balance	3	3	3
Reserve for Environmental Costs [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance	2	2	3
Valuation Allowances and Reserves, Charged to Cost and Expense	1	1	0
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	(1)	(1)	(1)
Valuation Allowances and Reserves, Balance	2	2	2
Other Reserves [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance	1	1	1
Valuation Allowances and Reserves, Charged to Cost and Expense	0	0	0
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	0	0	0
Valuation Allowances and Reserves, Balance	$ 1	$ 1	$ 1

Subsequent Events - Additional Information (Detail) (USD $)	12 Months Ended				3 Months Ended		12 Months Ended		3 Months Ended	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2012	Feb. 29, 2012	Mar. 31, 2015 Subsequent Event [Member]	Jan. 29, 2015 Subsequent Event [Member] MBbls	Dec. 31, 2013 Equity Distribution Agreement [Member]	Dec. 31, 2014 Equity Distribution Agreement [Member]	Mar. 31, 2015 Panola [Member] Subsequent Event [Member] mi MBbls	Dec. 31, 2014 Panola [Member] Subsequent Event [Member] MBbls	Jan. 29, 2015 Panola [Member] Subsequent Event [Member] in	Jan. 29, 2015 Enterprise [Member] Subsequent Event [Member]	Mar. 31, 2015 Discovery Producer Services LLC [Member] Subsequent Event [Member] MMcf mi	Feb. 19, 2015 Discovery Producer Services LLC [Member] Subsequent Event [Member] in
Subsequent Event [Line Items]
Distribution of dividend						$ 0.78
Distribution payable date					Feb. 13, 2015
Distribution record date					Feb. 09, 2015
Equity Method Investment, Ownership Percentage											15.00%	55.00%
Pipeline Diameter											10			20
Anticipated consideration to be paid for acquisition										$ 26,000,000
Pipeline Length In Miles									60				209
Business Combination, Capacity						50
Expected capacity per day										100
Aggregate consideration for acquisition	1,220,000,000
Common unitholders, units issued	113,949,868	89,045,139	5,148,500	30,701			1,839,430
Proceeds from issuance of common stock							87,000,000
Offering costs							1,000,000
Offer value of common stock remaining available for sale								$ 380,000,000
Capacity Of Plants or Pipelines Per Day													400

New Accounting Pronouncements (Notes)	12 Months Ended
New Accounting Pronouncements (Notes)	Dec. 31, 2014
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or 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 and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows and financial position.

Equity-Based Compensation (Policies)	12 Months Ended
Equity-Based Compensation (Policies)	Dec. 31, 2014
Equity-Based Compensation [Abstract]
Equity-Based Compensation [Policy Text Block]	Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units at the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date.

Goodwill and Intangible assets Schedule of Goodwill (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$ 154	$ 154
Natural Gas Services [Member]
Goodwill [Line Items]
Goodwill	82	82
NGL Logistics [Member]
Goodwill [Line Items]
Goodwill	35	35
Wholesale Propane Logistics [Member]
Goodwill [Line Items]
Goodwill	$ 37	$ 37

Supplementary Information - Condensed Consolidating Financial Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2012 Southeast Texas [Member]	Dec. 31, 2014 Parent Guarantor [Member]
Parent Company Only Financial Information [Line Items]
Ownership interest percentage in subsidiary	100.00%	100.00%