DCP Midstream (DCP-PC) 10-K 26 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 22, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	DCP
Entity Registrant Name	DCP MIDSTREAM, LP
Entity Central Index Key	1,338,065
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		143,309,828
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,060,364,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 156	$ 1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $8 and $4 million, respectively	773	652
Affiliates	191	134
Other	17	6
Inventories	68	72
Unrealized gains on derivative instruments	30	42
Collateral cash deposits	75	71
Other	12	16
Total current assets	1,322	994
Property, plant and equipment, net	8,983	9,069
Goodwill	231	236
Intangible assets, net	106	137
Investments in unconsolidated affiliates	3,050	2,969
Unrealized gains on derivative instruments	3	5
Other long-term assets	183	201
Total assets	13,878	13,611
Accounts payable:
Trade	989	677
Affiliates	68	48
Other	19	10
Current maturities of long-term debt	0	500
Derivative Instruments and Hedges, Liabilities	76	91
Accrued interest	71	72
Accrued taxes	58	49
Accrued wages and benefits	65	72
Capital spending accrual	39	20
Other	103	84
Total current liabilities	1,488	1,623
Long-term debt	4,707	4,907
Unrealized losses on derivative instruments	15	1
Deferred income taxes	29	28
Other long-term liabilities	201	199
Total liabilities	6,440	6,758
Commitments and contingent liabilities
Equity:
Predecessor equity	0	4,220
Limited partners (143,309,828 and 114,749,848 common units authorized, issued and outstanding, respectively)	6,772	2,591
Series A preferred limited partners (500,000 preferred units authorized, issued and outstanding, respectively)	491	0
General partner	154	18
Accumulated other comprehensive loss	(9)	(8)
Total partners’ equity	7,408	6,821
Noncontrolling interests	30	32
Total equity	7,438	6,853
Total liabilities and equity	$ 13,878	$ 13,611

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 8	$ 4
Common unitholders, units issued (in shares)	143,309,828	114,749,848
Common unitholders, units outstanding (in shares)	143,309,828	114,749,848
Preferred Units, Issued	500,000	0
Preferred Units, Outstanding	500,000	0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues:
Sales of natural gas, NGLs and condensate	$ 7,850	$ 6,269	$ 6,779
Transportation, processing and other	652	647	532
Trading and marketing (losses) gains, net	(40)	(23)	119
Total operating revenues	8,462	6,893	7,430
Operating costs and expenses:
Purchases and related costs	6,885	5,461	5,981
Operating and maintenance expense	661	670	732
Depreciation and amortization expense	379	378	377
General and administrative expense	290	292	281
Asset impairments	48	0	912
Other expense (income), net	11	(65)	10
Gain on sale of assets, net	(34)	(35)	(42)
Restructuring costs	0	13	11
Total operating costs and expenses	8,240	6,714	8,262
Operating income (loss)	222	179	(832)
Earnings from unconsolidated affiliates	303	282	184
Interest expense, net	(289)	(321)	(320)
Income (loss) before income taxes	236	140	(968)
Income tax (expense) benefit	(2)	(46)	102
Net income (loss)	234	94	(866)
Net income attributable to noncontrolling interests	(5)	(6)	(5)
Net income (loss) attributable to partners	229	88	(871)
Net loss attributable to predecessor operations	0	224	1,099
General partner’s interest in net income	(164)	(124)	(124)
Series A preferred limited partners' interest in net income	(4)	0	0
Net income allocable to limited partners	$ 61	$ 188	$ 104
Net income per limited partner unit - basic and diluted (in dollars per share)	$ 0.43	$ 1.64	$ 0.91
Weighted-average limited partner units outstanding - diluted (in shares)	143,300	114,700	114,600
Weighted Average Limited Partnership Units Outstanding, Basic	143,300	114,700	114,600
Third Party
Operating revenues:
Sales of natural gas, NGLs and condensate	$ 6,576	$ 5,317	$ 6,014
Operating costs and expenses:
Purchases and related costs	6,308	4,978	5,563
Affiliated Entity
Operating revenues:
Sales of natural gas, NGLs and condensate	1,274	952	765
Operating costs and expenses:
Purchases and related costs	$ 577	$ 483	$ 418

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 64	$ (20)	$ 89	$ 101	$ (39)	$ 89	$ (21)	$ 65	$ 234	$ 94	$ (866)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings									1	0	1
Total other comprehensive income									1	0	1
Total comprehensive income (loss)									235	94	(865)
Total comprehensive income attributable to noncontrolling interests									(5)	(6)	(5)
Total comprehensive income attributable to partners									$ 230	$ 88	$ (870)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net income (loss)	$ 234	$ 94	$ (866)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	379	378	377
Earnings from unconsolidated affiliates	(303)	(282)	(184)
Distributions from unconsolidated affiliates	367	356	217
Net unrealized losses (gains) on derivative instruments	28	139	(46)
Gain on sale of assets, net	(34)	(35)	(42)
Asset impairments	48	0	912
Other, net	32	68	(68)
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable	(194)	(247)	479
Inventories	4	(21)	(29)
Accounts payable	328	199	(381)
Increase (Decrease) in Other Operating Assets and Liabilities, Net	7	(4)	15
Net cash provided by operating activities	896	645	442
INVESTING ACTIVITIES:
Capital expenditures	(375)	(144)	(811)
Investments in unconsolidated affiliates, net	(148)	(53)	(64)
Proceeds from sale of assets	132	163	164
Net cash used in investing activities	(391)	(34)	(711)
FINANCING ACTIVITIES:
Proceeds from long-term debt	116	3,353	7,216
Payments of long-term debt	(811)	(3,628)	(7,196)
Payments of commercial paper, net	0	0	(1,012)
Proceeds from issuance of common limited partners units, net of offering costs	0	0	31
Proceeds from issuance of Series A preferred limited partner units, net of offering costs	487	0	0
Net change in advances to predecessor from DCP Midstream, LLC	418	157	1,697
Distributions to limited partners and general partner	(545)	(483)	(482)
Distributions to noncontrolling interests	(7)	(7)	(5)
Other	(8)	(5)	(4)
Net cash (used in) provided by financing activities	(350)	(613)	245
Net change in cash and cash equivalents	155	(2)	(24)
Cash and cash equivalents, beginning of period	1	3	27
Cash and cash equivalents, end of period	$ 156	$ 1	$ 3

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Mont Belvieu Fractionators [Member]	Series A Preferred Limited Partners [Member]	General Partner	Limited Partners	Limited PartnersMont Belvieu Fractionators [Member]	Accumulated Other Comprehensive (Loss) Income	Noncontrolling Interests
Beginning balance (Predecessor) at Dec. 31, 2014	$ 2,189
Beginning balance at Dec. 31, 2014	5,215			$ 18	$ 2,984		$ (9)	$ 33
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income | Predecessor	(1,099)
Net (loss) income	(866)			124	104			5
Other comprehensive income | Predecessor	0
Other comprehensive income	1			0	0		1	0
Net change in parent advances | Predecessor	3,197
Net change in parent advances	3,197
Deficit purchase price under carrying value of the Transaction		$ 1				$ 1
Proceeds from issuance of common units, net of offering costs | Predecessor	0
Proceeds from issuance of common units, net of offering costs	31			0	31			0
Proceeds from issuance of preferred units, net of offering costs	0
Distributions to limited partners and general partner	(482)			(124)	(358)
Distributions to noncontrolling interests	(5)							(5)
Ending balance (Predecessor) at Dec. 31, 2015	4,287
Ending balance at Dec. 31, 2015	7,092			18	2,762		(8)	33
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income | Predecessor	(224)
Net (loss) income	94			124	188			6
Other comprehensive income	0
Net change in parent advances | Predecessor	157
Net change in parent advances	157
Proceeds from issuance of preferred units, net of offering costs	0
Distributions to limited partners and general partner	(483)			(124)	(359)
Distributions to noncontrolling interests	(7)							(7)
Ending balance (Predecessor) at Dec. 31, 2016	4,220
Ending balance at Dec. 31, 2016	6,853			18	2,591		(8)	32
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	234		$ 4	164	61			5
Other comprehensive income	1						1
Net change in parent advances	418				418
Acquisition of the DCP Midstream Business | Predecessor	(4,220)
Acquisition of the DCP Midstream Business	(4,220)
Deficit purchase price under carrying value of the Transaction	3,092				3,094		(2)
Proceeds from issuance of common units, net of offering costs	1,125			92	1,033
Proceeds from issuance of preferred units, net of offering costs	487		487		0
Distributions to limited partners and general partner	(545)			(120)	(425)
Distributions to noncontrolling interests	(7)							(7)
Ending balance (Predecessor) at Dec. 31, 2017	0
Ending balance at Dec. 31, 2017	$ 7,438		$ 491	$ 154	$ 6,772		$ (9)	$ 30

Consolidated Statements of Cha8

Consolidated Statements of Changes in Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2017shares	Dec. 31, 2015shares
Issuance of 28,552,480 common units and 2,550,644 general partner units to DCP Midstream, LLC and affiliates [Member] | Limited Partners
Issuance of common units (in shares)	28,552,480
Issuance of 28,552,480 common units and 2,550,644 general partner units to DCP Midstream, LLC and affiliates [Member] | General Partner
Issuance of common units (in shares)	2,550,644
Issuance of Common Units [Member] | Limited Partners
Issuance of common units (in shares)		790,280
Issuance of 500,000 Series A Preferred Units [Member] | Series A Preferred Limited Partners [Member]
Issuance of preferred limited partnership units (in shares)	500,000

Description of Business and Bas

Description of Business and Basis of Presentation (notes)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	1. Description of Business and Basis of Presentation DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or the "Partnership" is a Delaware limited partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information regarding these segments, see Note 21 - 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 Enbridge Inc. and its affiliates, or Enbridge. Spectra Energy Corp owned 50% of DCP Midstream, LLC prior to the completion of its merger with Enbridge in the first quarter of 2017. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of December 31, 2017 , DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests. On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a 100% owned subsidiary of the Partnership, which closed effective January 1, 2017. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” Our predecessor results consist of all of the ownership interests of DCP Midstream, LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of The DCP Midstream Business for all periods presented. For additional information regarding the Transaction, see Note 4 - Acquisitions. 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. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	2 . 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 Trading Derivatives Mark-to-market method (a) Net basis in trading and marketing gains and losses Non-Trading Derivatives: Cash Flow Hedge Hedge method (b) Gross basis in the same consolidated statements of operations category as the related hedged item Fair Value Hedge Hedge method (b) Gross basis in the same consolidated statements of operations category as the related hedged item Normal Purchases or Normal Sales Accrual method (c) 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 (a) Net basis in trading and marketing gains and losses, net (a) 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 trading and marketing gains and losses, net during the current period. (b) 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. (c) 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. 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 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. 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 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 and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt. 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. 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/index 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 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/index 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. • Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs. Our trading and marketing of natural gas and NGLs consists of physical purchases and sales, as well as financial 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. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for commodity derivative activity net in the consolidated statements of operations as trading and marketing gains and losses . 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. Purchases and related costs - Purchases and related costs primarily includes (i) the cost of purchased commodities, including NGLs, natural gas and condensate, and (ii) fees incurred for transportation and fractionation of commodities. Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2017 , 2016 and 2015 . We had significant transactions with affiliates for the years ended December 31, 2017 , 2016 and 2015 . See Note 6, Agreements and Transactions with Related Parties and 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. Equity-Based Compensation — Liability classified equity-based compensation cost is remeasured at each reporting date at fair value, based on the closing security price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. We owned a corporation that filed its own federal and state corporate income tax returns, which we elected to convert to a limited liability company in 2016. 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 income tax 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 limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

New Accounting Pronouncements (

New Accounting Pronouncements (Notes)	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements, Policy [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. We adopted this ASU for interim and annual reporting periods beginning after December 15, 2017. The adoption of this ASU will have no impact on our consolidated cash flows. FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Although the new revenue recognition model is based on control, which differs from the previous model which was based a transfer of risks and rewards, we expect to identify similar performance obligations under Topic 606 as compared with deliverables and units of account previously identified under Topic 605. As a result, we expect the timing of our revenue to remain the same with respect to the majority of our contracts. There are certain contracts within our Gathering and Processing reportable segment where we previously recognized revenue for services provided to producers whereby under Topic 606 we have concluded that those contracts are not within the scope of Topic 606 and thus such amounts which were previously presented gross will now be presented net within ‘Purchases and related costs’. However, this change will not have any impact on our net income (loss), operating income (loss), cash flows, or the amount we present as gross margin in our Business Segments footnote. We also have certain contracts with customers whereby the customer reimburses us for costs to construct certain logistical connections to our operating assets which we own and operate. We previously accounted for these arrangements as a reduction to the cost basis of our long-lived assets which were amortized as a reduction to depreciation expense over the estimated useful life of the related assets. Under Topic 606 we will record these payments as deferred revenue which will be amortized into revenue over the contract term. Accordingly, we anticipate an increase to the amounts we present as gross margin within our Business Segment footnote, but do not anticipate a material impact to net income (loss), operating income (loss), or cash flows because the increase to depreciation expense will be offset by the increase to revenues. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several amendments to the standard which provided additional implementation guidance and deferred the effective date of the standard. We adopted the guidance using the modified retrospective method on the effective date of January 1, 2018. Based on these assessments we do not believe these changes will have a significant impact on the information presented to the users of our financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions	Acquisitions On January 1, 2017 , DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Dispositions	Dispositions In June 2017, we closed a transaction with Tallgrass Midstream, LLC to sell our 100% interest in our Douglas gathering system, which primarily consisted of approximately 1,500 miles of gathering lines within our Gathering and Processing segment, for approximately $129 million , subject to customary purchase price adjustments. As a result of this transaction, we recognized a gain of approximately $34 million , net of goodwill allocation, in the second quarter of 2017.

Agreements and Transactions wit

Agreements and Transactions with Affiliates	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Agreements and Transactions with Affiliates	Agreements and Transactions with Affiliates DCP Midstream, LLC Services Agreement and Other General and Administrative Charges Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. The following table summarizes employee related costs that were charged by DCP Midstream, LLC to the Partnership that are included in the consolidated statements of operations: Year Ended December 31, 2017 2016 2015 (millions) Employee related costs charged by DCP Midstream, LLC Operating and maintenance expense $ 197 $ 206 $ 224 General and administrative expense (including restructuring charges) $ 182 $ 197 $ 194 Phillips 66 and its Affiliates We sell a portion of our residue gas and NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party . Approximately 22% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2017 . The primary production commitment on certain contracts began a ratable wind down period in December 2014 and expires in January 2019. We ant icipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business. Enbridge and its Affiliates We sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and purchase commodities from Enbridge and its affiliates in the ordinary course of business. Unconsolidated Affiliates We have entered into 10 to 15 -year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, Texas Express Pipeline LLC, or Texas Express and Gulf Coast Express Pipeline, LLC, or Gulf Coast. Under the terms of these agreements, which commenced at each of the pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs. We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business. Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million , for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, 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 service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills. Summary of Transactions with Affiliates The following table summarizes our transactions with affiliates: Year Ended December 31, 2017 2016 2015 (millions) Phillips 66 (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $ 1,172 $ 909 $ 695 Purchases and related costs from affiliates $ 30 $ 18 $ — Operating and maintenance and general administrative expenses $ 2 $ 2 $ 4 Enbridge (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $ 48 $ — $ — Purchases and related costs from affiliates $ 43 $ 33 $ 50 Operating and maintenance and general administrative expenses $ 2 $ 4 $ 6 Unconsolidated affiliates: Sales of natural gas, NGLs and condensate to affiliates $ 54 $ 43 $ 70 Transportation, processing, and other to affiliates $ 5 $ 5 $ 3 Purchases and related costs from affiliates $ 504 $ 432 $ 368 We had balances with affiliates as follows: December 31, December 31, (millions) Phillips 66 (including its affiliates): Accounts receivable $ 156 $ 115 Accounts payable $ 6 $ 4 Other assets $ — $ 2 Enbridge (including its affiliates): Accounts receivable $ 11 $ 1 Accounts payable $ 9 $ 3 Other assets $ — $ 1 Other liabilities $ — $ 1 Unconsolidated affiliates: Accounts receivable $ 24 $ 18 Accounts payable $ 53 $ 41 Other assets $ 4 $ 5

Inventories

Inventories	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventories	Inventories Inventories were as follows: December 31, December 31, (millions) Natural gas $ 30 $ 28 NGLs 38 44 Total inventories $ 68 $ 72 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 and related costs in the consolidated statements of operations. We recognized lower of cost or market adjustments of $2 million , $3 million and $ 8 million during the years ended December 31, 2017 , 2016 and 2015 , respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment A summary of property, plant and equipment by classification is as follows: Depreciable December 31, December 31, (millions) Gathering and transmission systems 20 — 50 Years $ 8,473 $ 8,560 Processing, storage and terminal facilities 35 — 60 Years 5,128 5,134 Other 3 — 30 Years 557 502 Construction work in progress 374 171 Property, plant and equipment 14,532 14,367 Accumulated depreciation (5,549 ) (5,298 ) Property, plant and equipment, net $ 8,983 $ 9,069 Interest capitalized on construction projects was $7 million , less than $1 million and $ 32 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Depreciation expense was $367 million , $366 million and $ 358 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Asset Retirement Obligations 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. The following table summarizes changes in the asset retirement obligations included in our balance sheets: December 31, 2017 (a) 2016 (a) (millions) Balance, beginning of period $ 124 $ 120 Accretion expense 8 7 Change in ARO Estimate (6 ) (3 ) Balance, end of period $ 126 $ 124 (a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operating and maintenance expense in our consolidated statement of operations. Accretion expense for the year ended December 31, 2015 was $ 7 million .

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill We performed our annual goodwill assessment during the third quarter of 2017 at the reporting unit level, which is identified by assessing whether the 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 substantially exceeded its carrying value in our North reporting unit, the only reporting unit allocated goodwill included within our Gathering and Processing reportable segment and in our Marysville reporting unit included within our Logistics and Marketing reportable segment. For our Wholesale Propane reporting unit, which is included in our Logistics and Marketing reportable segment, the fair value exceeded the carrying value (including approximately $37 million of allocated goodwill) by approximately 5% . We concluded 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 (including forecasted volumes and commodity prices), as well as historical and other factors. 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. We expect that the fair value of our Wholesale Propane reporting unit will continue to exceed carrying value so long as our estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile propane prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. Changes to any one or combination of these factors, would result in changes to the reporting unit fair values discussed above which could lead to future impairment charges. Such potential impairment could impact our results of operations. The change in carrying amount of goodwill in each of our reportable segments was as follows: Year Ended December 31 2017 2016 (millions) Gathering and Processing Logistics and Marketing Total Gathering and Processing Logistics and Marketing Total Balance, beginning of period $ 164 $ 72 $ 236 $ 170 $ 72 $ 242 Dispositions (5 ) — (5 ) (6 ) — (6 ) Balance, end of period $ 159 $ 72 $ 231 $ 164 $ 72 $ 236 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, 2017 2016 (millions) Gross carrying amount $ 410 $ 410 Accumulated amortization (161 ) (151 ) Accumulated impairment (143 ) (122 ) Intangible assets, net $ 106 $ 137 We recorded amortization expense of $ 10 million , $ 12 million and $ 19 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, the remaining amortization periods ranged from approximately less than 1 year to 18 years, with a weighted-average remaining period of approximately 13 years. Estimated future amortization for these intangible assets is as follows: Estimated Future Amortization (millions) 2018 $ 10 2019 9 2020 9 2021 9 2022 9 Thereafter 60 Total $ 106

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates The following table summarizes our investments in unconsolidated affiliates: Carrying Value as of Percentage December 31, December 31, (millions) DCP Sand Hills Pipeline, LLC 66.67% $ 1,633 $ 1,507 Discovery Producer Services LLC 40.00% 362 385 DCP Southern Hills Pipeline, LLC 66.67% 739 754 Front Range Pipeline LLC 33.33% 165 165 Texas Express Pipeline LLC 10.00% 90 93 Panola Pipeline Company, LLC 15.00% 24 25 Mont Belvieu Enterprise Fractionator 12.50% 23 23 Mont Belvieu 1 Fractionator 20.00% 10 10 Other Various 4 7 Total investments in unconsolidated affiliates $ 3,050 $ 2,969 The following table represents the excess (deficit) of the carrying amount of the investment over (under) the underlying equity of our investments in unconsolidated affiliates as of December 31, 2017 and 2016: Excess (deficit) of Carrying Value over (under) Underlying Equity in Unconsolidated Affiliates December 31, December 31, (millions) DCP Sand Hills Pipeline, LLC $ 648 $ 662 Discovery Producer Services LLC (18 ) (20 ) DCP Southern Hills Pipeline, LLC 145 148 Front Range Pipeline LLC 4 5 Texas Express Pipeline LLC 3 3 Mont Belvieu 1 Fractionator (1 ) (2 ) Carrying amounts in excess or deficit of the underlying equity of our unconsolidated affiliates are amortized over the life of the underlying long-lived assets of the affiliate. Earnings from investments in unconsolidated affiliates were as follows: Year Ended December 31, 2017 2016 2015 (millions) DCP Sand Hills Pipeline, LLC $ 148 $ 110 63 Discovery Producer Services LLC 61 73 54 DCP Southern Hills Pipeline, LLC 47 44 18 Front Range Pipeline LLC 17 19 17 Texas Express Pipeline LLC 9 9 8 Mont Belvieu Enterprise Fractionator 13 16 15 Mont Belvieu 1 Fractionator 6 9 9 Other 2 2 — Total earnings from unconsolidated affiliates $ 303 $ 282 $ 184 The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Year Ended December 31, 2017 2016 2015 (millions) Statements of operations: Operating revenue $ 1,397 $ 1,311 $ 1,142 Operating expenses $ 647 $ 539 $ 541 Net income $ 747 $ 768 $ 600 December 31, December 31, (millions) Balance sheets: Current assets $ 244 $ 232 Long-term assets 5,319 5,274 Current liabilities (196 ) (156 ) Long-term liabilities (200 ) (205 ) Net assets $ 5,167 $ 5,145

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement Determination of Fair Value Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, 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 13 - Risk Management and Hedging Activities. Valuation Hierarchy Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. 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 exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions. Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices 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 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. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using 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. Benefits We offer certain eligible DCP Midstream, LLC executives the opportunity to participate in our DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan, or the EDC Plan. All amounts contributed to and earned by the EDC Plan’s investments are held in a trust account, which is managed by a third-party service provider. The trust account is invested in short-term money market securities and mutual funds. These investments are recorded at fair value, with any changes in fair value being recorded as a gain or loss in our consolidated statements of operations. Given that the value of the short-term money market securities and mutual funds are publicly traded and for which market prices are readily available, these investments are classified within Level 1. Interest Rate Derivative Assets and Liabilities We periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between the Partnership 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 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 other 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. During the year ended December 31, 2017 , we recognized impairments of property, plant and equipment, intangible assets and investment in unconsolidated affiliates of $ 48 million in our consolidated statement of operations as summarized in the table below. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Asset Impairments (millions) Property, plant and equipment $ 26 Intangible assets 21 Investment in unconsolidated affiliates 1 Total impairments $ 48 On January 3, 2017 , the Chicago Mercantile Exchange ("CME") modified its exchange rules to characterize daily variation margin amounts as "final settlement" values. The modified rule ("CME Rule 814") impacts derivative financial instruments traded on exchanges administered by the CME, including the New York Mercantile Exchange. As a result of this rule change, we are reporting the affected derivative instruments on a net basis on our balance sheet. The netting process results in the elimination of offsetting derivative assets, derivative liabilities and associated collateral cash deposits as if the underlying derivative instruments had settled on the balance sheet date. Through December 31, 2016, we historically reported such derivatives and associated collateral balances on a gross basis. Derivative transactions and associated collateral balances cleared on exchanges other than the CME continue to be reported on a gross basis. The following table presents the financial instruments carried at fair value as of December 31, 2017 and 2016 , by consolidated balance sheet caption and by valuation hierarchy, as described above: December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (millions) Current assets: Commodity derivatives (a) $ 10 $ 17 $ 3 $ 30 $ 5 $ 28 $ 9 $ 42 Short-term investments (b) $ 156 $ — $ — $ 156 $ — $ — $ — $ — Long-term assets: Commodity derivatives (c) $ 1 $ 1 $ 1 $ 3 $ — $ — $ 5 $ 5 Current liabilities: Commodity derivatives (d) $ (29 ) $ (34 ) $ (13 ) $ (76 ) $ (11 ) $ (57 ) $ (23 ) $ (91 ) Long-term liabilities: Commodity derivatives (e) $ (3 ) $ (11 ) $ (1 ) $ (15 ) $ (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 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, 2017 and 2016 , there were no transfers between 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 would reflect such items in the table below within the “Transfers into/out of Level 3” captions. We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities. Commodity Derivative Instruments Current Long-Term Current Long-Term (millions) Year ended December 31, 2017 (a): Beginning balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) included in earnings (b) 14 1 (44 ) (3 ) Transfers out of Level 3 (c) — — — 2 Settlements (13 ) — 36 — CME Rule 814 adjustment (7 ) (5 ) 18 — Ending balance $ 3 $ 1 $ (13 ) $ (1 ) Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 3 $ (4 ) $ (13 ) $ (1 ) Year ended December 31, 2016 (a): Beginning balance $ 35 $ 4 $ (23 ) $ (6 ) Net unrealized gains (losses) included in earnings (b) 3 1 (15 ) 6 Settlements (29 ) — 15 — Ending balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 9 $ 3 $ (23 ) $ 6 (a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2017 and 2016 . (b) Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net. (c) Amounts transferred out of Level 3 are reflected at fair value at the end of the period. 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, 2017 Product Group Fair Value Forward Curve Range (millions) Assets NGLs $ 4 $0.28-$0.82 Per gallon Liabilities NGLs $ (14 ) $0.20-$1.08 Per gallon Estimated Fair Value of Financial Instruments Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point. We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value. We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our Credit Agreement based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of December 31, 2017 and December 31, 2016 , the carrying value and fair value of our total debt, including current maturities, were as follows: December 31, 2017 December 31, 2016 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (millions) Total debt $ 4,736 $ 4,885 $ 5,430 $ 5,395 (a) Excludes unamortized issuance costs.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt December 31, December 31, (millions) Senior notes: Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 $ — $ 500 Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a) 450 450 Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 325 325 Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a) 600 600 Issued September 2011, interest at 4.750% payable semiannually, due September 2021 500 500 Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 350 350 Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 500 500 Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a) 300 300 Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 300 300 Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 450 450 Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 400 400 Junior subordinated notes: Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 550 550 Credit agreement: Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due December 2022 — 195 Fair value adjustments related to interest rate swap fair value hedges (a) 23 24 Unamortized issuance costs (29 ) (23 ) Unamortized discount (12 ) (14 ) Total debt 4,707 5,407 Current maturities of long-term debt — 500 Total long-term debt $ 4,707 $ 4,907 (a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $23 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt. Credit Agreement We are a party to a $ 1.4 billion unsecured revolving Credit Agreement which matures on December 6, 2022 . The Credit Agreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million , subject to requisite lender approval. The Credit Agreement may be extended for up to two additional one-year periods subject to requisite lender approval. Loans under the Credit Agreement may be used for working capital and other general partnership purposes including acquisitions. The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed: (a) 5.75 to 1.0 for the fiscal quarter ended December 31, 2017 (b) 5.50 to 1.0 for the fiscal quarter ending March 31, 2018, (c) 5.25 to 1.0 for the fiscal quarter ending June 30, 2018, and (d) 5.00 to 1.0 for each fiscal quarter ending thereafter; provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending June 30, 2018 or thereafter, the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of the three consecutive fiscal quarters, including the fiscal quarter in which the Qualified Acquisition occurs. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1% , plus (b) an applicable margin of 0.45% based on our current credit rating. The Credit Agreement incurs an annual facility fee of 0.30% based on our current credit rating. This fee is paid on drawn and undrawn portions of the approximately $1.4 billion revolving credit facility. As of December 31, 2017 , we had unused borrowing capacity of $1,375 million , net of $25 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by the unused borrowing capacity of $1,375 million as of December 31, 2017 . Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the December 6, 2022 maturity date. Senior Notes and Junior Subordinated Notes Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on their respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our Credit Agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes. The maturities of our long-term debt are as follows: Debt Maturities (millions) 2018 $ — 2019 775 2020 600 2021 500 2022 350 Thereafter 2,500 Total long-term debt $ 4,725

Risk Management and Hedging Act

Risk Management and Hedging Activities	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management and Hedging Activities	Risk Management and Hedging Activities Our operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage. Commodity Price Risk Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below. Natural Gas Asset Based Trading and Marketing 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 our natural gas storage facility 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 into 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 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, 2017 . Commodity 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 may 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. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2019. The commodity derivative instruments used for our hedging programs are a combination of direct NGL product, crude oil and natural gas hedges. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations as trading and marketing gains and (losses), net. NGL Proprietary Trading Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments 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. We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading. 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. We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt. Credit Risk Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 22% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2017 . This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to po st cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with o ur credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form. 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 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. • Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade. • Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of December 31, 2017 , 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 interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2017, we had less than $1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2017, we have not been required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2017, the net liability position would be offset by contracts in a net asset position. Collateral As of December 31, 2017 , we had cash deposits of $75 million , included in collateral cash deposits in our consolidated balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of December 31, 2017 , we held cash of $18 million , included in other current liabilities in our consolidated balance sheet, related to cash postings by third parties and letters of credit of $53 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements. Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller . 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, 2017 December 31, 2016 Gross Amounts Amounts Not Net Gross Amounts Amounts Not Net (millions) Assets: Commodity derivatives $ 33 $ — $ 33 $ 47 $ — $ 47 Liabilities: Commodity derivatives $ (91 ) $ — $ (91 ) $ (92 ) $ — $ (92 ) 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, 2017 and December 31, 2016 . Balance Sheet Line Item December 31, December 31, Balance Sheet Line Item December 31, December 31, (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 $ 30 $ 42 Unrealized losses on derivative instruments — current $ (76 ) $ (91 ) Unrealized gains on derivative instruments — long-term 3 5 Unrealized losses on derivative instruments — long-term (15 ) (1 ) Total $ 33 $ 47 Total $ (91 ) $ (92 ) 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, 2017 : Interest Commodity Foreign Total (millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Losses reclassified from AOCI to earnings — effective portion 1 — — 1 Deficit purchase price under carrying value of the Transaction $ (2 ) $ — $ — $ (2 ) Net deferred (losses) gains in AOCI (ending balance) $ (4 ) $ (6 ) $ 1 $ (9 ) (a) Relates to Discovery, an unconsolidated affiliate 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, 2016 : Interest Commodity Foreign Total (millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. For the years ended December 31, 2017 and 2016 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our consolidated statements of operations. For the years ended December 31, 2017 and 2016 , no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. Changes in the 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, 2017 2016 2015 (millions) Realized (losses) gains $ (12 ) $ 116 $ 73 Unrealized (losses) gains (28 ) (139 ) 46 Trading and marketing (losses) gains, net $ (40 ) $ (23 ) $ 119 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, 2017 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net Long Position (MMBtu) 2018 (2,701,000 ) (35,977,400 ) (19,656,392 ) 3,202,500 2019 (631,000 ) — (2,357,156 ) 7,177,500 2020 (50,000 ) — 238,548 3,660,000 December 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net (Short) Long Position (MMBtu) 2017 (1,470,000 ) (44,981,850 ) (22,225,821 ) 6,510,000 2018 (251,000 ) — 144,805 912,500 2019 (40,000 ) — (2,203 ) — 2020 (50,000 ) — 240,000 —

Partnership Equity and Distribu

Partnership Equity and Distributions	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Partnership Equity and Distributions	Partnership Equity and Distributions Preferred Units — On November 20, 2017 , we issued 500,000 of our Series A Preferred Units representing limited partnership interests at a price of $1,000 per unit. We used the net proceeds of $ 487 million from the issuance of the Series A Preferred Units to partially repay the $500 million 2.50% Senior Notes which were due on December 1, 2017. Distributions of the Series A Preferred Units are payable out of available cash, accrue and are cumulative from the date of original issuance of the Series A Preferred Units and are payable in arrears on June 15th and December 15th through and including December 15, 2022, and, after December 15, 2022, quarterly in arrears on March 15th, June 15th, September 15th, and December 15th of each year to holders of record as of the close of business on the first business day of the month. The initial distribution rate will be 7.375% per year of the $1,000 liquidation preference per unit (equal to $73.75 per unit). On and after December 15, 2022, distributions will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 5.148% . The Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. At any time prior to December 15, 2022, within 120 days of a ratings event, we may, at our option, redeem the Series A Preferred Units in whole, but not in part, at a redemption price per unit equal to $ 1,020 ( 102% of the liquidation preference), plus an amount equal to all accumulated and unpaid distributions. At any time on or after December 15, 2022, we may redeem, in whole or in part, the units at a redemption price of $1,000 per unit, plus an amount equal to all accumulated and unpaid distributions. Upon occurrence of a change in control triggering event, we may, at our option, (i) redeem the Series A Preferred Units, in whole or in part, within 120 days, by paying $1,000 per unit, plus all accumulated and unpaid distributions, and (ii) each holder of Series A Preferred Units will have the right (unless the Partnership provided notice of its election to redeem such holder’s Series A Preferred Units) to convert some or all of the Series A Preferred Units held by such holder on the change of control conversion date into a number of the Partnership’s common units per Series A Preferred Unit as defined in our Partnership Agreement. Holders of the Series A Preferred Units have no voting rights except for certain limited protective voting rights set forth in our Partnership Agreement. Common Units — In January 2017, we issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement as consideration for the Transaction that closed on January 1, 2017. For additional information regarding the Transaction, see Note 4 - Acquisitions. During the years ended December 31, 2017 and 2016 , we issued no common units pursuant to our 2014 equity distribution agreement. As of December 31, 2017, approximately $ 750 million of common units remained available for sale pursuant to our at-the-market program. During the year ended December 31, 2015, we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $ 31 million , net of commissions and offering costs of less than $ 1 million . 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 our general partner to: • provide for the proper conduct of our business, including reserves for future capital expenditures and anticipated credit needs; • comply with applicable law or any debt instrument or other agreement or obligation; • provide funds to make payments on the 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units; or • provide funds for distributions to our common 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 2% and limited partner interest of approximately 36% as of December 31, 2017. 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 or limited 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. As part of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions payable to our General Partner under our Partnership Agreement of up to $100 million annually through 2019 to target an approximate 1.0 times distribution coverage ratio. Under the terms of our amended Partnership Agreement, the amount of incentive distributions paid to our General Partner will be evaluated by our General Partner on both a quarterly and annual basis and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If no determination is made by our General Partner, the quarterly IDR giveback will be $20 million . The IDR giveback, of up to $100 million annually, will be subject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our amended Partnership Agreement) less the total annual distribution payable to our unitholders, adjusted to target an approximate 1.0 times coverage ratio. Distributions paid to the holders of the Partnership's incentive distribution rights were reduced by $40 million during the year ended December 31, 2017, in accordance with the Third Amendment to the Partnership Agreement. 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 2017 , 2016 and 2015 : Payment Date Per Unit Distribution Total Cash Distribution (millions) November 14, 2017 $ 0.7800 $ 155 August 14, 2017 $ 0.7800 $ 134 May 15, 2017 $ 0.7800 $ 135 February 14, 2017 $ 0.7800 $ 121 November 14, 2016 $ 0.7800 $ 120 August 12, 2016 $ 0.7800 $ 121 May 13, 2016 $ 0.7800 $ 121 February 12, 2016 $ 0.7800 $ 121 November 13, 2015 $ 0.7800 $ 120 August 14, 2015 $ 0.7800 $ 121 May 15, 2015 $ 0.7800 $ 121 February 13, 2015 $ 0.7800 $ 120

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Equity-Based Compensation On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 Long-Term Incentive Plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and, together with the 2012 LTIP and the 2016 LTIP, the “LTIP”). Any outstanding awards under the 2005 LTIP will remain outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued. On November 28, 2005, the board of directors of the General Partner adopted 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 the 2012 LTIP (the "2012 LTIP") for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provided 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. All awards under the LTIPs 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 on 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. Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the weighted average value of common shares of Phillips 66 and Enbridge as of the grant date. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The DCP Midstream LTIP is administered by the compensation committee of DCP Midstream, LLC's board of directors. All awards are subject to cliff vesting. Liability classified equity-based compensation expense was $ 23 million , $ 18 million and $ 8 million for the years ended December 31, 2017, 2016 and 2015, respectively. The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units: Vesting Period (years) Unrecognized Compensation Expense at December 31, 2017 (millions) Estimated Forfeiture Rate Weighted-Average Remaining Vesting (years) DCP Midstream LTIP: SPUs 3 $ 7 0%-11% 2 Phantom Units 1-3 $ 4 0%-11% 2 Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our General Partner. The DERs are paid in cash at the end of the performance period. The following table presents information related to SPUs: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2015 219,363 $ 47.89 Granted 111,930 $ 43.25 Forfeited (29,283 ) $ 48.02 Vested (a) (93,551 ) $ 41.02 Outstanding at December 31, 2015 208,459 $ 48.46 Granted 131,610 $ 45.31 Forfeited (8,463 ) $ 46.27 Vested (b) (98,295 ) $ 54.05 Outstanding at December 31, 2016 233,311 $ 44.41 Granted 98,628 $ 76.38 Forfeited (18,577 ) $ 50.31 Vested (c) (98,627 ) $ 58.80 Outstanding at December 31, 2017 214,735 $ 51.98 $ 55.61 Expected to vest 161,909 $ 54.52 $ 59.37 (a) The 2013 grants vested at 115% . (b) The 2014 grants vested at 130% . (c) The 2015 grants vested at 180% . The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiture rate and achievement of performance targets. The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performance units: Units Fair Value of Units Vested Unit-Based Liabilities Paid (millions) Vested or paid in cash in 2015 93,551 $ 4 $ 7 Vested or paid in cash in 2016 98,295 $ 7 $ 4 Vested or paid in cash in 2017 98,627 $ 11 $ 7 Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2015 171,202 $ 48.11 Granted 147,540 $ 47.84 Forfeited (17,400 ) $ 48.40 Vested (96,974 ) $ 44.00 Outstanding at December 31, 2015 204,368 $ 49.85 Granted 132,870 $ 45.33 Forfeited (3,240 ) $ 48.62 Vested (126,681 ) $ 50.13 Outstanding at December 31, 2016 207,317 $ 46.80 Granted 180,337 $ 59.43 Forfeited (16,677 ) $ 51.73 Vested (169,896 ) $ 53.35 Outstanding at December 31, 2017 201,081 $ 52.18 $ 62.56 Expected to vest 188,605 $ 52.13 $ 62.99 The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units: Units Fair Value of Units Vested Unit-Based Liabilities Paid (millions) Vested or paid in cash in 2015 96,974 $ 3 $ 5 Vested or paid in cash in 2016 126,681 $ 4 $ 5 Vested or paid in cash in 2017 169,896 $ 7 $ 4

Benefits

Benefits	12 Months Ended
	Dec. 31, 2017
Compensation and Retirement Disclosure [Abstract]
Benefits	We do not have our own employees. The employees supporting our operations are employees of DCP Services, LLC, for which we incur charges under the Services Agreement. All DCP Services, LLC employees who have reached the age of 18 and work at least 20 hours per week are eligible for participation in the 401(k) and retirement plan, to which a range of 4% to 7% of each eligible employee’s qualified earnings is contributed to the retirement plan, based on years of service. All new employees are automatically enrolled in the 401(k) plan at a 6% contribution level. Employees can opt out of these contribution level or change it at any time. Additionally, DCP Services, LLC matches employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During the years ended December 31, 2017, 2016 and 2015, we expensed plan contributions of $ 29 million , $ 29 million and $ 32 million , respectively. DCP Services, LLC offers certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf.

Net Income or Loss per Limited

Net Income or Loss per Limited Partner Unit	12 Months Ended
	Dec. 31, 2017
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 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.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	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. We owned a corporation that filed its own federal, foreign and state corporate income tax returns. During the year ended December 31, 2016, we elected to convert the corporation to a limited liability company for federal income tax purposes. The income tax (expense) benefit related to this corporation is included in our income tax (expense) benefit, along with state and local taxes of the limited liability entities. Income tax (expense) benefit consists of the following: Year Ended December 31, 2017 2016 2015 (millions) Current: Federal income tax expense $ — $ (19 ) $ — State income tax expense (1 ) (2 ) — Deferred: Federal income tax (expense) benefit — (22 ) 97 State income tax (expense) benefit (1 ) (3 ) 5 Total income tax (expense) benefit $ (2 ) $ (46 ) $ 102 As of December 31, 2017 and 2016, we had state deferred tax liabilities of $ 29 million and $ 28 million , respectively. The state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we recorded a reduction to our net federal deferred tax asset of $ 58 million resulting from the conversion of our corporation to a limited liability company. 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, primarily Texas. The State of Texas imposes a margin tax that is assessed at 0.75% , of taxable margin apportioned to Texas for each year ended December 31, 2017, 2016 and 2015.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our results of operations, financial position, or cash flow. Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6) 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 with similar types of operations. Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, 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, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous 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, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) 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 and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. 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 existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows. We make expenditures in connection with environmental matters as part of our normal operations. As of December 31, 2017 and 2016 , environmental liabilities included in our consolidated balance sheets as other current liabilities were $ 4 million and $ 4 million , respectively. As of December 31, 2017 and 2016 , environmental liabilities included in our consolidated balance sheets as other long-term liabilities were $ 8 million and $ 9 million , respectively. 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 $ 33 million , $ 37 million and $ 34 million for the years ended December 31, 2017 , 2016 , and 2015 , 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, 2017 : Future Minimum Rental Payments as of December 31, 2017 (millions) 2018 $ 37 2019 34 2020 30 2021 20 2022 15 Thereafter 28 Total minimum rental payments $ 164

Restructuring (Notes)

Restructuring (Notes)	12 Months Ended
	Dec. 31, 2017
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	Restructuring Costs In April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain operational and corporate positions, as part of ongoing effort to create efficiencies, reduce costs and transform our business. As a result of this headcount reduction, we recorded one-time employee termination costs of approximately $ 13 million , which are included in restructuring costs in our consolidated statements of operations for the year ended December 31, 2016. In January 2015, we announced the initial phase of this cost reduction plan, which involved the elimination of certain corporate employee positions. As a result, we recorded employee termination costs of approximately $ 11 million , all of which were paid during the year ended December 31, 2015, and are included in restructuring costs in the consolidated statement of operations for the year ended December 31, 2015.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business Segments	Business Segments Our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing. 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. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 - Summary of Significant Accounting Policies. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering condensate. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminations column. The following tables set forth our segment information: Year Ended December 31, 2017 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 5,467 $ 7,757 $ — $ (4,762 ) $ 8,462 Gross margin (a) $ 1,377 $ 200 $ — $ — $ 1,577 Operating and maintenance expense (602 ) (41 ) (18 ) — (661 ) Depreciation and amortization expense (343 ) (14 ) (22 ) — (379 ) General and administrative expense (19 ) (11 ) (260 ) — (290 ) Asset impairments (48 ) — — — (48 ) Other expense — (11 ) — — (11 ) Gain on sale of assets, net 34 — — — 34 Earnings from unconsolidated affiliates 60 243 — — 303 Interest expense — — (289 ) — (289 ) Income tax expense — — (2 ) — (2 ) Net income (loss) $ 459 $ 366 $ (591 ) $ — $ 234 Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net income (loss) attributable to partners $ 454 $ 366 $ (591 ) $ — $ 229 Non-cash derivative mark-to-market (b) $ (24 ) $ (4 ) $ — $ — $ (28 ) Non-cash lower of cost or market adjustments $ — $ 2 $ — $ — $ 2 Capital expenditures $ 350 $ 3 $ 22 $ — $ 375 Investments in unconsolidated affiliates, net $ 1 $ 147 $ — $ — $ 148 Year Ended December 31, 2016 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 4,490 $ 6,186 $ — $ (3,783 ) $ 6,893 Gross margin (a) $ 1,227 $ 205 $ — $ — $ 1,432 Operating and maintenance expense (611 ) (43 ) (16 ) — (670 ) Depreciation and amortization expense (344 ) (15 ) (19 ) — (378 ) General and administrative expense (14 ) (9 ) (269 ) — (292 ) Other income (expense), net 73 (5 ) (3 ) — 65 Gain on sale of assets, net 19 16 — — 35 Restructuring costs — — (13 ) — (13 ) Earnings from unconsolidated affiliates 73 209 — — 282 Interest expense — — (321 ) — (321 ) Income tax expense — — (46 ) — (46 ) Net income (loss) $ 423 $ 358 $ (687 ) $ — $ 94 Net income attributable to noncontrolling interests (6 ) — — — (6 ) Net income (loss) attributable to partners $ 417 $ 358 $ (687 ) $ — $ 88 Non-cash derivative mark-to-market (b) $ (119 ) $ (20 ) $ — $ — $ (139 ) Non-cash lower of cost or market adjustments $ — $ 3 $ — $ — $ 3 Capital expenditures $ 107 $ 10 $ 27 $ — $ 144 Investments in unconsolidated affiliates, net $ 1 $ 52 $ — $ — $ 53 Year Ended December 31, 2015 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 4,910 $ 6,487 $ — $ (3,967 ) $ 7,430 Gross margin (a) $ 1,213 $ 236 $ — $ — $ 1,449 Operating and maintenance expense (668 ) (49 ) (15 ) — (732 ) Depreciation and amortization expense (343 ) (16 ) (18 ) — (377 ) General and administrative expense (22 ) (11 ) (248 ) — (281 ) Asset impairment (876 ) (9 ) (27 ) — (912 ) Other expense (1 ) (8 ) (1 ) — (10 ) Gain on sale of assets, net 42 — — — 42 Restructuring costs — — (11 ) — (11 ) Earnings from unconsolidated affiliates 54 130 — — 184 Interest expense — — (320 ) — (320 ) Income tax benefit — — 102 — 102 Net (loss) income $ (601 ) $ 273 $ (538 ) $ — $ (866 ) Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net (loss) income attributable to partners $ (606 ) $ 273 $ (538 ) $ — $ (871 ) Non-cash derivative mark-to-market (b) $ 47 $ (1 ) $ — $ — $ 46 Non-cash lower of cost or market adjustments $ — $ 8 $ — $ — $ 8 Capital expenditures $ 729 $ 52 $ 30 $ — $ 811 Investments in unconsolidated affiliates, net $ 15 $ 49 $ — $ — $ 64 December 31, December 31, 2017 2016 (millions) Segment long-term assets: Gathering and Processing $ 8,943 $ 9,053 Logistics and Marketing 3,348 3,278 Other (c) 265 286 Total long-term assets 12,556 12,617 Current assets 1,322 994 Total assets $ 13,878 $ 13,611 (a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, 2017 2016 2015 (millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 290 $ 306 $ 293 Cash paid for income taxes, net of income tax refunds $ 2 $ 2 $ 3 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable and accrued liabilities $ 58 $ 27 $ 35 Other non-cash changes in property, plant and equipment $ 5 $ (3 ) $ (19 ) Contribution of assets from our predecessor $ — $ — $ 1,500

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data (Unaudited) [Abstract]
Quarterly Financial Information [Text Block]	Quarterly Financial Data (Unaudited) Our consolidated results of operations by quarter for the years ended December 31, 2017 and 2016 were as follows (millions, except per unit amounts): 2017 First Second Third Fourth Year Ended December 31, 2017 Total operating revenues $ 2,121 $ 1,949 $ 2,055 $ 2,337 $ 8,462 Operating income (loss) $ 101 $ 78 $ (19 ) $ 62 $ 222 Net income (loss) $ 101 $ 89 $ (20 ) $ 64 $ 234 Net income attributable to noncontrolling interests $ — $ (1 ) $ — $ (4 ) $ (5 ) Net income (loss) attributable to partners $ 101 $ 88 $ (20 ) $ 60 $ 229 Net income (loss) allocable to limited partners $ 59 $ 47 $ (59 ) $ 14 $ 61 Basic and diluted net income (loss) per limited partner unit $ 0.41 $ 0.33 $ (0.41 ) $ 0.10 $ 0.43 2016 First Second Third Fourth Year Ended December 31, 2016 Total operating revenues $ 1,464 $ 1,623 $ 1,823 $ 1,983 $ 6,893 Operating income (loss) $ 80 $ (12 ) $ 92 $ 19 $ 179 Net income (loss) $ 65 $ (21 ) $ 89 $ (39 ) $ 94 Net income attributable to noncontrolling interests $ — $ (1 ) $ — $ (5 ) $ (6 ) Net income (loss) attributable to partners $ 65 $ (22 ) $ 89 $ (44 ) $ 88 Net loss attributable to predecessor operations $ (7 ) $ (67 ) $ (31 ) $ (119 ) $ (224 ) Net income allocable to limited partners $ 41 $ 14 $ 89 $ 44 $ 188 Basic and diluted net income per limited partner unit $ 0.36 $ 0.12 $ 0.78 $ 0.38 $ 1.64

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Condensed Consolidating Financial Information The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, 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, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. Condensed Consolidating Balance Sheet December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) ASSETS Current assets: Cash and cash equivalents $ — $ 155 $ 1 $ — $ 156 Accounts receivable, net — — 981 — 981 Inventories — — 68 — 68 Other — — 117 — 117 Total current assets — 155 1,167 — 1,322 Property, plant and equipment, net — — 8,983 — 8,983 Goodwill and intangible assets, net — — 337 — 337 Advances receivable — consolidated subsidiaries 2,895 1,614 — (4,509 ) — Investments in consolidated subsidiaries 4,513 7,522 — (12,035 ) — Investments in unconsolidated affiliates — — 3,050 — 3,050 Other long-term assets — — 186 — 186 Total assets $ 7,408 $ 9,291 $ 13,723 $ (16,544 ) $ 13,878 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 71 $ 1,417 $ — $ 1,488 Advances payable — consolidated subsidiaries — — 4,509 (4,509 ) — Long-term debt — 4,707 — — 4,707 Other long-term liabilities — — 245 — 245 Total liabilities — 4,778 6,171 (4,509 ) 6,440 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 7,408 4,517 7,527 (12,035 ) 7,417 Accumulated other comprehensive loss — (4 ) (5 ) — (9 ) Total partners’ equity 7,408 4,513 7,522 (12,035 ) 7,408 Noncontrolling interests — — 30 — 30 Total equity 7,408 4,513 7,552 (12,035 ) 7,438 Total liabilities and equity $ 7,408 $ 9,291 $ 13,723 $ (16,544 ) $ 13,878 Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 792 — 792 Inventories — — 72 — 72 Other — — 129 — 129 Total current assets — — 994 — 994 Property, plant and equipment, net — — 9,069 — 9,069 Goodwill and intangible assets, net — — 373 — 373 Advances receivable — consolidated subsidiaries 2,953 2,760 — (5,713 ) — Investments in consolidated subsidiaries 3,868 6,587 — (10,455 ) — Investments in unconsolidated affiliates — — 2,969 — 2,969 Other long-term assets — — 206 — 206 Total assets $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 72 $ 1,051 $ — $ 1,123 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,713 (5,713 ) — Long-term debt — 4,907 — — 4,907 Other long-term liabilities — — 228 — 228 Total liabilities — 5,479 6,992 (5,713 ) 6,758 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 6,821 3,871 6,592 (10,455 ) 6,829 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 6,821 3,868 6,587 (10,455 ) 6,821 Noncontrolling interests — — 32 — 32 Total equity 6,821 3,868 6,619 (10,455 ) 6,853 Total liabilities and equity $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 7,850 $ — $ 7,850 Transportation, processing and other — — 652 — 652 Trading and marketing losses, net — — (40 ) — (40 ) Total operating revenues — — 8,462 — 8,462 Operating costs and expenses: Purchases and related costs — — 6,885 — 6,885 Operating and maintenance expense — — 661 — 661 Depreciation and amortization expense — — 379 — 379 General and administrative expense — — 290 — 290 Asset impairments — — 48 — 48 Gain on sale of assets, net — — (34 ) — (34 ) Other expense, net — — 11 — 11 Total operating costs and expenses — — 8,240 — 8,240 Operating income — — 222 — 222 Interest expense, net — (289 ) — — (289 ) Income from consolidated subsidiaries 229 518 — (747 ) — Earnings from unconsolidated affiliates — — 303 — 303 Income before income taxes 229 229 525 (747 ) 236 Income tax expense — — (2 ) — (2 ) Net income 229 229 523 (747 ) 234 Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net income attributable to partners $ 229 $ 229 $ 518 $ (747 ) $ 229 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ 229 $ 229 $ 523 $ (747 ) $ 234 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive income 230 230 523 (748 ) 235 Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive income attributable to partners $ 230 $ 230 $ 518 $ (748 ) $ 230 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 6,269 $ — $ 6,269 Transportation, processing and other — — 647 — 647 Trading and marketing losses, net — — (23 ) — (23 ) Total operating revenues — — 6,893 — 6,893 Operating costs and expenses: Purchases and related costs — — 5,461 — 5,461 Operating and maintenance expense — — 670 — 670 Depreciation and amortization expense — — 378 — 378 General and administrative expense — — 292 — 292 Gain on sale of assets, net — — (35 ) — (35 ) Restructuring costs — — 13 — 13 Other income, net — — (65 ) — (65 ) Total operating costs and expenses — — 6,714 — 6,714 Operating income — — 179 — 179 Interest expense, net — (321 ) — — (321 ) Income from consolidated subsidiaries 88 409 — (497 ) — Earnings from unconsolidated affiliates — — 282 — 282 Income before income taxes 88 88 461 (497 ) 140 Income tax expense — — (46 ) — (46 ) Net income 88 88 415 (497 ) 94 Net income attributable to noncontrolling interests — — (6 ) — (6 ) Net income attributable to partners $ 88 $ 88 $ 409 $ (497 ) $ 88 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ 88 $ 88 $ 415 $ (497 ) $ 94 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — — — — — Other comprehensive income from consolidated subsidiaries — — — — — Total other comprehensive income — — — — — Total comprehensive income 88 88 415 (497 ) 94 Total comprehensive income attributable to noncontrolling interests — — (6 ) — (6 ) Total comprehensive income attributable to partners $ 88 $ 88 $ 409 $ (497 ) $ 88 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 6,779 $ — $ 6,779 Transportation, processing and other — — 532 — 532 Trading and marketing gains, net — — 119 — 119 Total operating revenues — — 7,430 — 7,430 Operating costs and expenses: Purchases and related costs — — 5,981 — 5,981 Operating and maintenance expense — — 732 — 732 Depreciation and amortization expense — — 377 — 377 General and administrative expense — — 281 — 281 Asset impairments — — 912 — 912 Gain on sale of assets, net — — (42 ) — (42 ) Restructuring costs — — 11 — 11 Other expense, net — — 10 — 10 Total operating costs and expenses — — 8,262 — 8,262 Operating loss — — (832 ) — (832 ) Interest expense, net — (320 ) — — (320 ) Income from consolidated subsidiaries (871 ) (551 ) — 1,422 — Earnings from unconsolidated affiliates — — 184 — 184 Loss before income taxes (871 ) (871 ) (648 ) 1,422 (968 ) Income tax benefit — — 102 — 102 Net loss (871 ) (871 ) (546 ) 1,422 (866 ) Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net loss attributable to partners $ (871 ) $ (871 ) $ (551 ) $ 1,422 $ (871 ) Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ (871 ) $ (871 ) $ (546 ) $ 1,422 $ (866 ) Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive loss (870 ) (870 ) (546 ) 1,421 (865 ) Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive loss attributable to partners $ (870 ) $ (870 ) $ (551 ) $ 1,421 $ (870 ) Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (283 ) $ 1,179 $ — $ 896 INVESTING ACTIVITIES: Intercompany transfers 58 1,141 — (1,199 ) — Capital expenditures — — (375 ) — (375 ) Investments in unconsolidated affiliates — — (148 ) — (148 ) Proceeds from sale of assets — — 132 — 132 Net cash provided by (used in) investing activities 58 1,141 (391 ) (1,199 ) (391 ) FINANCING ACTIVITIES: Intercompany transfers — — (1,199 ) 1,199 — Proceeds from long-term debt — 116 — — 116 Payments of long-term debt — (811 ) — — (811 ) Proceeds from issuance of preferred Series A units, net of offering costs 487 — — — 487 Net change in advances to predecessor from DCP Midstream, LLC — — 418 — 418 Distributions to limited partners and general partner (545 ) — — — (545 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Other — (8 ) — — (8 ) Net cash used in financing activities (58 ) (703 ) (788 ) 1,199 (350 ) Net change in cash and cash equivalents — 155 — — 155 Cash and cash equivalents, beginning of period — — 1 — 1 Cash and cash equivalents, end of period $ — $ 155 $ 1 $ — $ 156 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (305 ) $ 950 $ — $ 645 INVESTING ACTIVITIES: Intercompany transfers 483 585 — (1,068 ) — Capital expenditures — — (144 ) — (144 ) Investments in unconsolidated affiliates, net — — (53 ) — (53 ) Proceeds from sale of assets — — 163 — 163 Net cash provided by (used in) investing activities 483 585 (34 ) (1,068 ) (34 ) FINANCING ACTIVITIES: Intercompany transfers — — (1,068 ) 1,068 — Proceeds from long-term debt — 3,353 — — 3,353 Payments of long-term debt — (3,628 ) — — (3,628 ) Net change in advances to predecessor from DCP Midstream, LLC — — 157 — 157 Distributions to limited partners and general partner (483 ) — — — (483 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Other — (5 ) — — (5 ) Net cash used in financing activities (483 ) (280 ) (918 ) 1,068 (613 ) Net change in cash and cash equivalents — — (2 ) — (2 ) Cash and cash equivalents, beginning of period — — 3 — 3 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2015 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (311 ) $ 753 $ — $ 442 INVESTING ACTIVITIES: Intercompany transfers (1,049 ) 1,283 — (234 ) — Capital expenditures — — (811 ) — (811 ) Investments in unconsolidated affiliates, net — — (64 ) — (64 ) Proceeds from sale of assets — — 164 — 164 Net cash (used in) provided by investing activities (1,049 ) 1,283 (711 ) (234 ) (711 ) FINANCING ACTIVITIES: Intercompany transfers — — (234 ) 234 — Proceeds from long-term debt — 7,216 — — 7,216 Payments of long-term debt — (7,196 ) — — (7,196 ) Payments of commercial paper, net — (1,012 ) — — (1,012 ) Proceeds from issuance of common units, net of offering costs 31 — — — 31 Net change in advances to predecessor from DCP Midstream, LLC 1,500 — 197 — 1,697 Distributions to limited partners and general partner (482 ) — — — (482 ) Distributions to noncontrolling interests — — (5 ) — (5 ) Other — (4 ) — — (4 ) Net cash provided by (used in) financing activities 1,049 (996 ) (42 ) 234 245 Net change in cash and cash equivalents — (24 ) — — (24 ) Cash and cash equivalents, beginning of year — 24 3 — 27 Cash and cash equivalents, end of year $ — $ — $ 3 $ — $ 3

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 23, 2018 , 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 14, 2018 to unitholders of record on February 7, 2018 . On February 14, 2018 , the Partnership distributed $40 million of IDR givebacks to our owners, in conjunction with the quarterly distribution, that were previously withheld under the amended Partnership agreement.

Description of Business and B34

Description of Business and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies [Text Block]	The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP.
Equity Method Investments	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.

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Use of Estimates	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.
Purchases and Related Costs	Purchases and related costs - Purchases and related costs primarily includes (i) the cost of purchased commodities, including NGLs, natural gas and condensate, and (ii) fees incurred for transportation and fractionation of commodities.
Major Customers, Policy [Policy Text Block]	Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2017 , 2016 and 2015 . We had significant transactions with affiliates for the years ended December 31, 2017 , 2016 and 2015 . See Note 6, Agreements and Transactions with Related Parties and Affiliates.
Revenue Recognition, Policy [Policy Text Block]	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. 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/index 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 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/index 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. • Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs. Our trading and marketing of natural gas and NGLs consists of physical purchases and sales, as well as financial 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. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for commodity derivative activity net in the consolidated statements of operations as trading and marketing gains and losses . 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.
Cash and Cash Equivalents, Policy [Policy Text Block]	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 [Policy Text Block]	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.
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.
Property, Plant and Equipment, Policy [Policy Text Block]	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.
Interest Capitalization, Policy [Policy Text Block]	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 and Environmental Cost, Policy [Policy Text Block]	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, Policy [Policy Text Block]	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 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.
Equity and Cost Method Investments, Policy [Policy Text Block]	Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates. 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.
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block]	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 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.
Debt, Policy [Policy Text Block]	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 and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt.
Derivatives, Policy [Policy Text Block]	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.
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	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 Trading Derivatives Mark-to-market method (a) Net basis in trading and marketing gains and losses Non-Trading Derivatives: Cash Flow Hedge Hedge method (b) Gross basis in the same consolidated statements of operations category as the related hedged item Fair Value Hedge Hedge method (b) Gross basis in the same consolidated statements of operations category as the related hedged item Normal Purchases or Normal Sales Accrual method (c) 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 (a) Net basis in trading and marketing gains and losses, net (a) 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 trading and marketing gains and losses, net during the current period. (b) 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. (c) 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.
Environmental Costs, Policy [Policy Text Block]	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.
Income Tax, Policy [Policy Text Block]	Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. We owned a corporation that filed its own federal and state corporate income tax returns, which we elected to convert to a limited liability company in 2016. 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 income tax returns of each partner.
Earnings Per Unit	Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

Agreements and Transactions w36

Agreements and Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transaction [Line Items]
Schedule of Fees Incurred and Other Fees Paid	The following table summarizes employee related costs that were charged by DCP Midstream, LLC to the Partnership that are included in the consolidated statements of operations: Year Ended December 31, 2017 2016 2015 (millions) Employee related costs charged by DCP Midstream, LLC Operating and maintenance expense $ 197 $ 206 $ 224 General and administrative expense (including restructuring charges) $ 182 $ 197 $ 194
Summary of Transactions with Affiliates	The following table summarizes our transactions with affiliates: Year Ended December 31, 2017 2016 2015 (millions) Phillips 66 (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $ 1,172 $ 909 $ 695 Purchases and related costs from affiliates $ 30 $ 18 $ — Operating and maintenance and general administrative expenses $ 2 $ 2 $ 4 Enbridge (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $ 48 $ — $ — Purchases and related costs from affiliates $ 43 $ 33 $ 50 Operating and maintenance and general administrative expenses $ 2 $ 4 $ 6 Unconsolidated affiliates: Sales of natural gas, NGLs and condensate to affiliates $ 54 $ 43 $ 70 Transportation, processing, and other to affiliates $ 5 $ 5 $ 3 Purchases and related costs from affiliates $ 504 $ 432 $ 368 We had balances with affiliates as follows: December 31, December 31, (millions) Phillips 66 (including its affiliates): Accounts receivable $ 156 $ 115 Accounts payable $ 6 $ 4 Other assets $ — $ 2 Enbridge (including its affiliates): Accounts receivable $ 11 $ 1 Accounts payable $ 9 $ 3 Other assets $ — $ 1 Other liabilities $ — $ 1 Unconsolidated affiliates: Accounts receivable $ 24 $ 18 Accounts payable $ 53 $ 41 Other assets $ 4 $ 5

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories were as follows: December 31, December 31, (millions) Natural gas $ 30 $ 28 NGLs 38 44 Total inventories $ 68 $ 72

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Classification of Property, Plant and Equipment	A summary of property, plant and equipment by classification is as follows: Depreciable December 31, December 31, (millions) Gathering and transmission systems 20 — 50 Years $ 8,473 $ 8,560 Processing, storage and terminal facilities 35 — 60 Years 5,128 5,134 Other 3 — 30 Years 557 502 Construction work in progress 374 171 Property, plant and equipment 14,532 14,367 Accumulated depreciation (5,549 ) (5,298 ) Property, plant and equipment, net $ 8,983 $ 9,069
Asset Retirement Obligations	Asset Retirement Obligations 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. The following table summarizes changes in the asset retirement obligations included in our balance sheets: December 31, 2017 (a) 2016 (a) (millions) Balance, beginning of period $ 124 $ 120 Accretion expense 8 7 Change in ARO Estimate (6 ) (3 ) Balance, end of period $ 126 $ 124 (a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operating and maintenance expense in our consolidated statement of operations. Accretion expense for the year ended December 31, 2015 was $ 7 million .

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The change in carrying amount of goodwill in each of our reportable segments was as follows: Year Ended December 31 2017 2016 (millions) Gathering and Processing Logistics and Marketing Total Gathering and Processing Logistics and Marketing Total Balance, beginning of period $ 164 $ 72 $ 236 $ 170 $ 72 $ 242 Dispositions (5 ) — (5 ) (6 ) — (6 ) Balance, end of period $ 159 $ 72 $ 231 $ 164 $ 72 $ 236
Finite-Lived Intangible Assets [Line Items]
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	Estimated Future Amortization (millions) 2018 $ 10 2019 9 2020 9 2021 9 2022 9 Thereafter 60 Total $ 106
Schedule of Finite-Lived Intangible Assets [Table Text Block]	December 31, 2017 2016 (millions) Gross carrying amount $ 410 $ 410 Accumulated amortization (161 ) (151 ) Accumulated impairment (143 ) (122 ) Intangible assets, net $ 106 $ 137

Investments in Unconsolidated40

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
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 December 31, December 31, (millions) DCP Sand Hills Pipeline, LLC 66.67% $ 1,633 $ 1,507 Discovery Producer Services LLC 40.00% 362 385 DCP Southern Hills Pipeline, LLC 66.67% 739 754 Front Range Pipeline LLC 33.33% 165 165 Texas Express Pipeline LLC 10.00% 90 93 Panola Pipeline Company, LLC 15.00% 24 25 Mont Belvieu Enterprise Fractionator 12.50% 23 23 Mont Belvieu 1 Fractionator 20.00% 10 10 Other Various 4 7 Total investments in unconsolidated affiliates $ 3,050 $ 2,969
Schedule of Excess (Deficit) of Carrying Value of Investment over Underlying Equity of Unconsolidated Affiliates [Table Text Block]	The following table represents the excess (deficit) of the carrying amount of the investment over (under) the underlying equity of our investments in unconsolidated affiliates as of December 31, 2017 and 2016: Excess (deficit) of Carrying Value over (under) Underlying Equity in Unconsolidated Affiliates December 31, December 31, (millions) DCP Sand Hills Pipeline, LLC $ 648 $ 662 Discovery Producer Services LLC (18 ) (20 ) DCP Southern Hills Pipeline, LLC 145 148 Front Range Pipeline LLC 4 5 Texas Express Pipeline LLC 3 3 Mont Belvieu 1 Fractionator (1 ) (2 )
Schedule Of Earnings From Investment In Unconsolidated Affiliates [Table Text Block]	Earnings from investments in unconsolidated affiliates were as follows: Year Ended December 31, 2017 2016 2015 (millions) DCP Sand Hills Pipeline, LLC $ 148 $ 110 63 Discovery Producer Services LLC 61 73 54 DCP Southern Hills Pipeline, LLC 47 44 18 Front Range Pipeline LLC 17 19 17 Texas Express Pipeline LLC 9 9 8 Mont Belvieu Enterprise Fractionator 13 16 15 Mont Belvieu 1 Fractionator 6 9 9 Other 2 2 — Total earnings from unconsolidated affiliates $ 303 $ 282 $ 184
Equity Method Investment Summarized Financial Information, Statement of Operations [Table Text Block]	The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Year Ended December 31, 2017 2016 2015 (millions) Statements of operations: Operating revenue $ 1,397 $ 1,311 $ 1,142 Operating expenses $ 647 $ 539 $ 541 Net income $ 747 $ 768 $ 600
Equity Method Investment Summarized Financial Information Balance Sheet Table [Table Text Block]	December 31, December 31, (millions) Balance sheets: Current assets $ 244 $ 232 Long-term assets 5,319 5,274 Current liabilities (196 ) (156 ) Long-term liabilities (200 ) (205 ) Net assets $ 5,167 $ 5,145

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Impaired Assets	Asset Impairments (millions) Property, plant and equipment $ 26 Intangible assets 21 Investment in unconsolidated affiliates 1 Total impairments $ 48
Financial Instruments Carried at Fair Value	December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (millions) Current assets: Commodity derivatives (a) $ 10 $ 17 $ 3 $ 30 $ 5 $ 28 $ 9 $ 42 Short-term investments (b) $ 156 $ — $ — $ 156 $ — $ — $ — $ — Long-term assets: Commodity derivatives (c) $ 1 $ 1 $ 1 $ 3 $ — $ — $ 5 $ 5 Current liabilities: Commodity derivatives (d) $ (29 ) $ (34 ) $ (13 ) $ (76 ) $ (11 ) $ (57 ) $ (23 ) $ (91 ) Long-term liabilities: Commodity derivatives (e) $ (3 ) $ (11 ) $ (1 ) $ (15 ) $ (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 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.
Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation	Commodity Derivative Instruments Current Long-Term Current Long-Term (millions) Year ended December 31, 2017 (a): Beginning balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) included in earnings (b) 14 1 (44 ) (3 ) Transfers out of Level 3 (c) — — — 2 Settlements (13 ) — 36 — CME Rule 814 adjustment (7 ) (5 ) 18 — Ending balance $ 3 $ 1 $ (13 ) $ (1 ) Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 3 $ (4 ) $ (13 ) $ (1 ) Year ended December 31, 2016 (a): Beginning balance $ 35 $ 4 $ (23 ) $ (6 ) Net unrealized gains (losses) included in earnings (b) 3 1 (15 ) 6 Settlements (29 ) — 15 — Ending balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 9 $ 3 $ (23 ) $ 6 (a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2017 and 2016 . (b) Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net. (c) Amounts transferred out of Level 3 are reflected at fair value at the end of the period.
Schedule of Valuation Processes	December 31, 2017 Product Group Fair Value Forward Curve Range (millions) Assets NGLs $ 4 $0.28-$0.82 Per gallon Liabilities NGLs $ (14 ) $0.20-$1.08 Per gallon
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our Credit Agreement based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of December 31, 2017 and December 31, 2016 , the carrying value and fair value of our total debt, including current maturities, were as follows: December 31, 2017 December 31, 2016 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (millions) Total debt $ 4,736 $ 4,885 $ 5,430 $ 5,395 (a) Excludes unamortized issuance costs.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt	December 31, December 31, (millions) Senior notes: Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 $ — $ 500 Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a) 450 450 Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 325 325 Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a) 600 600 Issued September 2011, interest at 4.750% payable semiannually, due September 2021 500 500 Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 350 350 Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 500 500 Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a) 300 300 Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 300 300 Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 450 450 Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 400 400 Junior subordinated notes: Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 550 550 Credit agreement: Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due December 2022 — 195 Fair value adjustments related to interest rate swap fair value hedges (a) 23 24 Unamortized issuance costs (29 ) (23 ) Unamortized discount (12 ) (14 ) Total debt 4,707 5,407 Current maturities of long-term debt — 500 Total long-term debt $ 4,707 $ 4,907 (a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $23 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt.
Future Maturities of Long-Term Debt	The maturities of our long-term debt are as follows: Debt Maturities (millions) 2018 $ — 2019 775 2020 600 2021 500 2022 350 Thereafter 2,500 Total long-term debt $ 4,725

Risk Management and Hedging A43

Risk Management and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Gross and Net Amounts of Derivative Instruments	December 31, 2017 December 31, 2016 Gross Amounts Amounts Not Net Gross Amounts Amounts Not Net (millions) Assets: Commodity derivatives $ 33 $ — $ 33 $ 47 $ — $ 47 Liabilities: Commodity derivatives $ (91 ) $ — $ (91 ) $ (92 ) $ — $ (92 )
Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value	December 31, 2017 and December 31, 2016 . Balance Sheet Line Item December 31, December 31, Balance Sheet Line Item December 31, December 31, (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 $ 30 $ 42 Unrealized losses on derivative instruments — current $ (76 ) $ (91 ) Unrealized gains on derivative instruments — long-term 3 5 Unrealized losses on derivative instruments — long-term (15 ) (1 ) Total $ 33 $ 47 Total $ (91 ) $ (92 )
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	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, 2017 : Interest Commodity Foreign Total (millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Losses reclassified from AOCI to earnings — effective portion 1 — — 1 Deficit purchase price under carrying value of the Transaction $ (2 ) $ — $ — $ (2 ) Net deferred (losses) gains in AOCI (ending balance) $ (4 ) $ (6 ) $ 1 $ (9 ) (a) Relates to Discovery, an unconsolidated affiliate 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, 2016 : Interest Commodity Foreign Total (millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate.
Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments	Commodity Derivatives: Statements of Operations Line Item Year Ended December 31, 2017 2016 2015 (millions) Realized (losses) gains $ (12 ) $ 116 $ 73 Unrealized (losses) gains (28 ) (139 ) 46 Trading and marketing (losses) gains, net $ (40 ) $ (23 ) $ 119
Schedule of Net Long or Short Positions Expected to be Realized	December 31, 2017 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net Long Position (MMBtu) 2018 (2,701,000 ) (35,977,400 ) (19,656,392 ) 3,202,500 2019 (631,000 ) — (2,357,156 ) 7,177,500 2020 (50,000 ) — 238,548 3,660,000 December 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net (Short) Long Position (MMBtu) 2017 (1,470,000 ) (44,981,850 ) (22,225,821 ) 6,510,000 2018 (251,000 ) — 144,805 912,500 2019 (40,000 ) — (2,203 ) — 2020 (50,000 ) — 240,000 —

Partnership Equity and Distri44

Partnership Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Cash Distribution	The following table presents our cash distributions paid in 2017 , 2016 and 2015 : Payment Date Per Unit Distribution Total Cash Distribution (millions) November 14, 2017 $ 0.7800 $ 155 August 14, 2017 $ 0.7800 $ 134 May 15, 2017 $ 0.7800 $ 135 February 14, 2017 $ 0.7800 $ 121 November 14, 2016 $ 0.7800 $ 120 August 12, 2016 $ 0.7800 $ 121 May 13, 2016 $ 0.7800 $ 121 February 12, 2016 $ 0.7800 $ 121 November 13, 2015 $ 0.7800 $ 120 August 14, 2015 $ 0.7800 $ 121 May 15, 2015 $ 0.7800 $ 121 February 13, 2015 $ 0.7800 $ 120

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Fair Value of Unvested Awards	The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units: Vesting Period (years) Unrecognized Compensation Expense at December 31, 2017 (millions) Estimated Forfeiture Rate Weighted-Average Remaining Vesting (years) DCP Midstream LTIP: SPUs 3 $ 7 0%-11% 2 Phantom Units 1-3 $ 4 0%-11% 2
Schedule of Nonvested Share Activity	Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our General Partner. The DERs are paid in cash at the end of the performance period. The following table presents information related to SPUs: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2015 219,363 $ 47.89 Granted 111,930 $ 43.25 Forfeited (29,283 ) $ 48.02 Vested (a) (93,551 ) $ 41.02 Outstanding at December 31, 2015 208,459 $ 48.46 Granted 131,610 $ 45.31 Forfeited (8,463 ) $ 46.27 Vested (b) (98,295 ) $ 54.05 Outstanding at December 31, 2016 233,311 $ 44.41 Granted 98,628 $ 76.38 Forfeited (18,577 ) $ 50.31 Vested (c) (98,627 ) $ 58.80 Outstanding at December 31, 2017 214,735 $ 51.98 $ 55.61 Expected to vest 161,909 $ 54.52 $ 59.37 (a) The 2013 grants vested at 115% . (b) The 2014 grants vested at 130% . (c) The 2015 grants vested at 180% . Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2015 171,202 $ 48.11 Granted 147,540 $ 47.84 Forfeited (17,400 ) $ 48.40 Vested (96,974 ) $ 44.00 Outstanding at December 31, 2015 204,368 $ 49.85 Granted 132,870 $ 45.33 Forfeited (3,240 ) $ 48.62 Vested (126,681 ) $ 50.13 Outstanding at December 31, 2016 207,317 $ 46.80 Granted 180,337 $ 59.43 Forfeited (16,677 ) $ 51.73 Vested (169,896 ) $ 53.35 Outstanding at December 31, 2017 201,081 $ 52.18 $ 62.56 Expected to vest 188,605 $ 52.13 $ 62.99
Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Performance-Based Units, Vested and Expected to Vest [Table Text Block]	The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units: Units Fair Value of Units Vested Unit-Based Liabilities Paid (millions) Vested or paid in cash in 2015 96,974 $ 3 $ 5 Vested or paid in cash in 2016 126,681 $ 4 $ 5 Vested or paid in cash in 2017 169,896 $ 7 $ 4 The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performance units: Units Fair Value of Units Vested Unit-Based Liabilities Paid (millions) Vested or paid in cash in 2015 93,551 $ 4 $ 7 Vested or paid in cash in 2016 98,295 $ 7 $ 4 Vested or paid in cash in 2017 98,627 $ 11 $ 7

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	Income tax (expense) benefit consists of the following: Year Ended December 31, 2017 2016 2015 (millions) Current: Federal income tax expense $ — $ (19 ) $ — State income tax expense (1 ) (2 ) — Deferred: Federal income tax (expense) benefit — (22 ) 97 State income tax (expense) benefit (1 ) (3 ) 5 Total income tax (expense) benefit $ (2 ) $ (46 ) $ 102

Commitments and Contingent Li47

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future Minimum Rental Payments as of December 31, 2017 (millions) 2018 $ 37 2019 34 2020 30 2021 20 2022 15 Thereafter 28 Total minimum rental payments $ 164

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	The following tables set forth our segment information: Year Ended December 31, 2017 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 5,467 $ 7,757 $ — $ (4,762 ) $ 8,462 Gross margin (a) $ 1,377 $ 200 $ — $ — $ 1,577 Operating and maintenance expense (602 ) (41 ) (18 ) — (661 ) Depreciation and amortization expense (343 ) (14 ) (22 ) — (379 ) General and administrative expense (19 ) (11 ) (260 ) — (290 ) Asset impairments (48 ) — — — (48 ) Other expense — (11 ) — — (11 ) Gain on sale of assets, net 34 — — — 34 Earnings from unconsolidated affiliates 60 243 — — 303 Interest expense — — (289 ) — (289 ) Income tax expense — — (2 ) — (2 ) Net income (loss) $ 459 $ 366 $ (591 ) $ — $ 234 Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net income (loss) attributable to partners $ 454 $ 366 $ (591 ) $ — $ 229 Non-cash derivative mark-to-market (b) $ (24 ) $ (4 ) $ — $ — $ (28 ) Non-cash lower of cost or market adjustments $ — $ 2 $ — $ — $ 2 Capital expenditures $ 350 $ 3 $ 22 $ — $ 375 Investments in unconsolidated affiliates, net $ 1 $ 147 $ — $ — $ 148 Year Ended December 31, 2016 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 4,490 $ 6,186 $ — $ (3,783 ) $ 6,893 Gross margin (a) $ 1,227 $ 205 $ — $ — $ 1,432 Operating and maintenance expense (611 ) (43 ) (16 ) — (670 ) Depreciation and amortization expense (344 ) (15 ) (19 ) — (378 ) General and administrative expense (14 ) (9 ) (269 ) — (292 ) Other income (expense), net 73 (5 ) (3 ) — 65 Gain on sale of assets, net 19 16 — — 35 Restructuring costs — — (13 ) — (13 ) Earnings from unconsolidated affiliates 73 209 — — 282 Interest expense — — (321 ) — (321 ) Income tax expense — — (46 ) — (46 ) Net income (loss) $ 423 $ 358 $ (687 ) $ — $ 94 Net income attributable to noncontrolling interests (6 ) — — — (6 ) Net income (loss) attributable to partners $ 417 $ 358 $ (687 ) $ — $ 88 Non-cash derivative mark-to-market (b) $ (119 ) $ (20 ) $ — $ — $ (139 ) Non-cash lower of cost or market adjustments $ — $ 3 $ — $ — $ 3 Capital expenditures $ 107 $ 10 $ 27 $ — $ 144 Investments in unconsolidated affiliates, net $ 1 $ 52 $ — $ — $ 53 Year Ended December 31, 2015 : Gathering and Processing Logistics and Marketing Other Eliminations Total (millions) Total operating revenue $ 4,910 $ 6,487 $ — $ (3,967 ) $ 7,430 Gross margin (a) $ 1,213 $ 236 $ — $ — $ 1,449 Operating and maintenance expense (668 ) (49 ) (15 ) — (732 ) Depreciation and amortization expense (343 ) (16 ) (18 ) — (377 ) General and administrative expense (22 ) (11 ) (248 ) — (281 ) Asset impairment (876 ) (9 ) (27 ) — (912 ) Other expense (1 ) (8 ) (1 ) — (10 ) Gain on sale of assets, net 42 — — — 42 Restructuring costs — — (11 ) — (11 ) Earnings from unconsolidated affiliates 54 130 — — 184 Interest expense — — (320 ) — (320 ) Income tax benefit — — 102 — 102 Net (loss) income $ (601 ) $ 273 $ (538 ) $ — $ (866 ) Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net (loss) income attributable to partners $ (606 ) $ 273 $ (538 ) $ — $ (871 ) Non-cash derivative mark-to-market (b) $ 47 $ (1 ) $ — $ — $ 46 Non-cash lower of cost or market adjustments $ — $ 8 $ — $ — $ 8 Capital expenditures $ 729 $ 52 $ 30 $ — $ 811 Investments in unconsolidated affiliates, net $ 15 $ 49 $ — $ — $ 64 December 31, December 31, 2017 2016 (millions) Segment long-term assets: Gathering and Processing $ 8,943 $ 9,053 Logistics and Marketing 3,348 3,278 Other (c) 265 286 Total long-term assets 12,556 12,617 Current assets 1,322 994 Total assets $ 13,878 $ 13,611 (a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.

Supplemental Cash Flow Inform49

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Summary of Supplemental Cash Flow Information	Year Ended December 31, 2017 2016 2015 (millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 290 $ 306 $ 293 Cash paid for income taxes, net of income tax refunds $ 2 $ 2 $ 3 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable and accrued liabilities $ 58 $ 27 $ 35 Other non-cash changes in property, plant and equipment $ 5 $ (3 ) $ (19 ) Contribution of assets from our predecessor $ — $ — $ 1,500

Quarterly Financial Data (Una50

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data (Unaudited) [Abstract]
Quarterly Financial Information [Table Text Block]	2017 First Second Third Fourth Year Ended December 31, 2017 Total operating revenues $ 2,121 $ 1,949 $ 2,055 $ 2,337 $ 8,462 Operating income (loss) $ 101 $ 78 $ (19 ) $ 62 $ 222 Net income (loss) $ 101 $ 89 $ (20 ) $ 64 $ 234 Net income attributable to noncontrolling interests $ — $ (1 ) $ — $ (4 ) $ (5 ) Net income (loss) attributable to partners $ 101 $ 88 $ (20 ) $ 60 $ 229 Net income (loss) allocable to limited partners $ 59 $ 47 $ (59 ) $ 14 $ 61 Basic and diluted net income (loss) per limited partner unit $ 0.41 $ 0.33 $ (0.41 ) $ 0.10 $ 0.43 2016 First Second Third Fourth Year Ended December 31, 2016 Total operating revenues $ 1,464 $ 1,623 $ 1,823 $ 1,983 $ 6,893 Operating income (loss) $ 80 $ (12 ) $ 92 $ 19 $ 179 Net income (loss) $ 65 $ (21 ) $ 89 $ (39 ) $ 94 Net income attributable to noncontrolling interests $ — $ (1 ) $ — $ (5 ) $ (6 ) Net income (loss) attributable to partners $ 65 $ (22 ) $ 89 $ (44 ) $ 88 Net loss attributable to predecessor operations $ (7 ) $ (67 ) $ (31 ) $ (119 ) $ (224 ) Net income allocable to limited partners $ 41 $ 14 $ 89 $ 44 $ 188 Basic and diluted net income per limited partner unit $ 0.36 $ 0.12 $ 0.78 $ 0.38 $ 1.64

Condensed Consolidating Finan51

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	Condensed Consolidating Balance Sheet December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) ASSETS Current assets: Cash and cash equivalents $ — $ 155 $ 1 $ — $ 156 Accounts receivable, net — — 981 — 981 Inventories — — 68 — 68 Other — — 117 — 117 Total current assets — 155 1,167 — 1,322 Property, plant and equipment, net — — 8,983 — 8,983 Goodwill and intangible assets, net — — 337 — 337 Advances receivable — consolidated subsidiaries 2,895 1,614 — (4,509 ) — Investments in consolidated subsidiaries 4,513 7,522 — (12,035 ) — Investments in unconsolidated affiliates — — 3,050 — 3,050 Other long-term assets — — 186 — 186 Total assets $ 7,408 $ 9,291 $ 13,723 $ (16,544 ) $ 13,878 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 71 $ 1,417 $ — $ 1,488 Advances payable — consolidated subsidiaries — — 4,509 (4,509 ) — Long-term debt — 4,707 — — 4,707 Other long-term liabilities — — 245 — 245 Total liabilities — 4,778 6,171 (4,509 ) 6,440 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 7,408 4,517 7,527 (12,035 ) 7,417 Accumulated other comprehensive loss — (4 ) (5 ) — (9 ) Total partners’ equity 7,408 4,513 7,522 (12,035 ) 7,408 Noncontrolling interests — — 30 — 30 Total equity 7,408 4,513 7,552 (12,035 ) 7,438 Total liabilities and equity $ 7,408 $ 9,291 $ 13,723 $ (16,544 ) $ 13,878 Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 792 — 792 Inventories — — 72 — 72 Other — — 129 — 129 Total current assets — — 994 — 994 Property, plant and equipment, net — — 9,069 — 9,069 Goodwill and intangible assets, net — — 373 — 373 Advances receivable — consolidated subsidiaries 2,953 2,760 — (5,713 ) — Investments in consolidated subsidiaries 3,868 6,587 — (10,455 ) — Investments in unconsolidated affiliates — — 2,969 — 2,969 Other long-term assets — — 206 — 206 Total assets $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 72 $ 1,051 $ — $ 1,123 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,713 (5,713 ) — Long-term debt — 4,907 — — 4,907 Other long-term liabilities — — 228 — 228 Total liabilities — 5,479 6,992 (5,713 ) 6,758 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 6,821 3,871 6,592 (10,455 ) 6,829 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 6,821 3,868 6,587 (10,455 ) 6,821 Noncontrolling interests — — 32 — 32 Total equity 6,821 3,868 6,619 (10,455 ) 6,853 Total liabilities and equity $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611
Condensed Income Statement	Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 6,269 $ — $ 6,269 Transportation, processing and other — — 647 — 647 Trading and marketing losses, net — — (23 ) — (23 ) Total operating revenues — — 6,893 — 6,893 Operating costs and expenses: Purchases and related costs — — 5,461 — 5,461 Operating and maintenance expense — — 670 — 670 Depreciation and amortization expense — — 378 — 378 General and administrative expense — — 292 — 292 Gain on sale of assets, net — — (35 ) — (35 ) Restructuring costs — — 13 — 13 Other income, net — — (65 ) — (65 ) Total operating costs and expenses — — 6,714 — 6,714 Operating income — — 179 — 179 Interest expense, net — (321 ) — — (321 ) Income from consolidated subsidiaries 88 409 — (497 ) — Earnings from unconsolidated affiliates — — 282 — 282 Income before income taxes 88 88 461 (497 ) 140 Income tax expense — — (46 ) — (46 ) Net income 88 88 415 (497 ) 94 Net income attributable to noncontrolling interests — — (6 ) — (6 ) Net income attributable to partners $ 88 $ 88 $ 409 $ (497 ) $ 88 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 6,779 $ — $ 6,779 Transportation, processing and other — — 532 — 532 Trading and marketing gains, net — — 119 — 119 Total operating revenues — — 7,430 — 7,430 Operating costs and expenses: Purchases and related costs — — 5,981 — 5,981 Operating and maintenance expense — — 732 — 732 Depreciation and amortization expense — — 377 — 377 General and administrative expense — — 281 — 281 Asset impairments — — 912 — 912 Gain on sale of assets, net — — (42 ) — (42 ) Restructuring costs — — 11 — 11 Other expense, net — — 10 — 10 Total operating costs and expenses — — 8,262 — 8,262 Operating loss — — (832 ) — (832 ) Interest expense, net — (320 ) — — (320 ) Income from consolidated subsidiaries (871 ) (551 ) — 1,422 — Earnings from unconsolidated affiliates — — 184 — 184 Loss before income taxes (871 ) (871 ) (648 ) 1,422 (968 ) Income tax benefit — — 102 — 102 Net loss (871 ) (871 ) (546 ) 1,422 (866 ) Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net loss attributable to partners $ (871 ) $ (871 ) $ (551 ) $ 1,422 $ (871 ) Condensed Consolidating Statement of Operations Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 7,850 $ — $ 7,850 Transportation, processing and other — — 652 — 652 Trading and marketing losses, net — — (40 ) — (40 ) Total operating revenues — — 8,462 — 8,462 Operating costs and expenses: Purchases and related costs — — 6,885 — 6,885 Operating and maintenance expense — — 661 — 661 Depreciation and amortization expense — — 379 — 379 General and administrative expense — — 290 — 290 Asset impairments — — 48 — 48 Gain on sale of assets, net — — (34 ) — (34 ) Other expense, net — — 11 — 11 Total operating costs and expenses — — 8,240 — 8,240 Operating income — — 222 — 222 Interest expense, net — (289 ) — — (289 ) Income from consolidated subsidiaries 229 518 — (747 ) — Earnings from unconsolidated affiliates — — 303 — 303 Income before income taxes 229 229 525 (747 ) 236 Income tax expense — — (2 ) — (2 ) Net income 229 229 523 (747 ) 234 Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net income attributable to partners $ 229 $ 229 $ 518 $ (747 ) $ 229
Condensed Statement of Comprehensive Income	Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ (871 ) $ (871 ) $ (546 ) $ 1,422 $ (866 ) Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive loss (870 ) (870 ) (546 ) 1,421 (865 ) Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive loss attributable to partners $ (870 ) $ (870 ) $ (551 ) $ 1,421 $ (870 ) Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ 88 $ 88 $ 415 $ (497 ) $ 94 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — — — — — Other comprehensive income from consolidated subsidiaries — — — — — Total other comprehensive income — — — — — Total comprehensive income 88 88 415 (497 ) 94 Total comprehensive income attributable to noncontrolling interests — — (6 ) — (6 ) Total comprehensive income attributable to partners $ 88 $ 88 $ 409 $ (497 ) $ 88 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) Net income $ 229 $ 229 $ 523 $ (747 ) $ 234 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive income 230 230 523 (748 ) 235 Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive income attributable to partners $ 230 $ 230 $ 518 $ (748 ) $ 230
Condensed Consolidating Statements of Cash Flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (283 ) $ 1,179 $ — $ 896 INVESTING ACTIVITIES: Intercompany transfers 58 1,141 — (1,199 ) — Capital expenditures — — (375 ) — (375 ) Investments in unconsolidated affiliates — — (148 ) — (148 ) Proceeds from sale of assets — — 132 — 132 Net cash provided by (used in) investing activities 58 1,141 (391 ) (1,199 ) (391 ) FINANCING ACTIVITIES: Intercompany transfers — — (1,199 ) 1,199 — Proceeds from long-term debt — 116 — — 116 Payments of long-term debt — (811 ) — — (811 ) Proceeds from issuance of preferred Series A units, net of offering costs 487 — — — 487 Net change in advances to predecessor from DCP Midstream, LLC — — 418 — 418 Distributions to limited partners and general partner (545 ) — — — (545 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Other — (8 ) — — (8 ) Net cash used in financing activities (58 ) (703 ) (788 ) 1,199 (350 ) Net change in cash and cash equivalents — 155 — — 155 Cash and cash equivalents, beginning of period — — 1 — 1 Cash and cash equivalents, end of period $ — $ 155 $ 1 $ — $ 156 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (305 ) $ 950 $ — $ 645 INVESTING ACTIVITIES: Intercompany transfers 483 585 — (1,068 ) — Capital expenditures — — (144 ) — (144 ) Investments in unconsolidated affiliates, net — — (53 ) — (53 ) Proceeds from sale of assets — — 163 — 163 Net cash provided by (used in) investing activities 483 585 (34 ) (1,068 ) (34 ) FINANCING ACTIVITIES: Intercompany transfers — — (1,068 ) 1,068 — Proceeds from long-term debt — 3,353 — — 3,353 Payments of long-term debt — (3,628 ) — — (3,628 ) Net change in advances to predecessor from DCP Midstream, LLC — — 157 — 157 Distributions to limited partners and general partner (483 ) — — — (483 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Other — (5 ) — — (5 ) Net cash used in financing activities (483 ) (280 ) (918 ) 1,068 (613 ) Net change in cash and cash equivalents — — (2 ) — (2 ) Cash and cash equivalents, beginning of period — — 3 — 3 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2015 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (311 ) $ 753 $ — $ 442 INVESTING ACTIVITIES: Intercompany transfers (1,049 ) 1,283 — (234 ) — Capital expenditures — — (811 ) — (811 ) Investments in unconsolidated affiliates, net — — (64 ) — (64 ) Proceeds from sale of assets — — 164 — 164 Net cash (used in) provided by investing activities (1,049 ) 1,283 (711 ) (234 ) (711 ) FINANCING ACTIVITIES: Intercompany transfers — — (234 ) 234 — Proceeds from long-term debt — 7,216 — — 7,216 Payments of long-term debt — (7,196 ) — — (7,196 ) Payments of commercial paper, net — (1,012 ) — — (1,012 ) Proceeds from issuance of common units, net of offering costs 31 — — — 31 Net change in advances to predecessor from DCP Midstream, LLC 1,500 — 197 — 1,697 Distributions to limited partners and general partner (482 ) — — — (482 ) Distributions to noncontrolling interests — — (5 ) — (5 ) Other — (4 ) — — (4 ) Net cash provided by (used in) financing activities 1,049 (996 ) (42 ) 234 245 Net change in cash and cash equivalents — (24 ) — — (24 ) Cash and cash equivalents, beginning of year — 24 3 — 27 Cash and cash equivalents, end of year $ — $ — $ 3 $ — $ 3

Description of Business and B52

Description of Business and Basis of Presentation - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Investments in Greater Than 20%
Business Acquisition [Line Items]
Equity method ownership investment (as percent)	20.00%
Investments in Less Than 20%
Business Acquisition [Line Items]
Equity method ownership investment (as percent)	20.00%
DCP Midstream Operating, LP
Business Acquisition [Line Items]
Ownership interest percentage by parent	100.00%
DCP Midstream, LLC | DCP Midstream GP, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	100.00%
DCP Midstream, LLC | DCP Midstream LP
Business Acquisition [Line Items]
Ownership interest percentage by parent	38.10%
Phillips 66 | DCP Midstream, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%
Enbridge | DCP Midstream, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent	50.00%
Spectra Energy | DCP Midstream, LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent		50.00%

Acquisitions - Additional Infor

Acquisitions - Additional Information (Detail) - DCP Midstream, LLC - USD ($)	Jan. 01, 2017	Dec. 31, 2017
Business Acquisition [Line Items]
Cash acquired	$ 424,000,000
Debt assumed	$ 3,150,000,000
Incentive distribution, potential annual reduction (up to)		$ 100,000,000
Common Units
Business Acquisition [Line Items]
Equity interest issued, number of units (in shares)	28,552,480
General Partner Units
Business Acquisition [Line Items]
Equity interest issued, number of units (in shares)	2,550,644

Dispositions (Details)

Dispositions (Details) $ in Millions	Jun. 01, 2017USD ($)mi	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets, net		$ 34	$ 35	$ 42
Douglas Gathering System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest disposed	100.00%
Length of gathering lines (in miles) | mi	1,500
Proceeds from sale	$ 129
Gain on sale of assets, net	$ 34

Agreements and Transactions w55

Agreements and Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Affiliated Entity | Gulf Coast Express [Member]
Related Party Transaction [Line Items]
Term of agreement	10 years
Affiliated Entity | Sand Hills
Related Party Transaction [Line Items]
Term of agreement	15 years
Annual service fee	$ 5
Affiliated Entity | Southern Hills
Related Party Transaction [Line Items]
Term of agreement	15 years
Annual service fee	$ 5
Affiliated Entity | Front Range
Related Party Transaction [Line Items]
Term of agreement	15 years
Affiliated Entity | Texas Express
Related Party Transaction [Line Items]
Term of agreement	15 years
Affiliated Entity | Natural Gas Liquids
Related Party Transaction [Line Items]
Production Committed To Related Parties, Percent	22.00%
Affiliated Entity | Phillips 66 | Chevron Phillips Chemical LLC
Related Party Transaction [Line Items]
Equity method ownership investment (as percent)	50.00%
Operating Expense
Related Party Transaction [Line Items]
Labor and related expense	$ 197	$ 206	$ 224
General and Administrative Expense
Related Party Transaction [Line Items]
Labor and related expense	$ 182	$ 197	$ 194

Agreements and Transactions w56

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	$ 7,850	$ 6,269	$ 6,779
Transportation, processing and other	652	647	532
Purchases and related costs	6,885	5,461	5,981
Operating and maintenance expense	661	670	732
Affiliated Entity | Phillips 66
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	1,172	909	695
Purchases and related costs	30	18	0
Operating and maintenance expense	2	2	4
Affiliated Entity | Enbridge
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	48	0	0
Purchases and related costs	43	33	50
Operating and maintenance expense	2	4	6
Affiliated Entity | Unconsolidated Affiliates
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate	54	43	70
Transportation, processing and other	5	5	3
Purchases and related costs	$ 504	$ 432	$ 368
Natural Gas Liquids | Affiliated Entity
Related Party Transaction [Line Items]
Production Committed To Related Parties, Percent	22.00%

Agreements and Transactions w57

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Accounts receivable	$ 191	$ 134
Accounts payable	68	48
Phillips 66
Related Party Transaction [Line Items]
Accounts receivable	156	115
Accounts payable	6	4
Other assets	0	2
Enbridge
Related Party Transaction [Line Items]
Accounts receivable	11	1
Accounts payable	9	3
Other assets	0	1
Other liabilities	0	1
Unconsolidated Affiliates
Related Party Transaction [Line Items]
Accounts receivable	24	18
Accounts payable	53	41
Other assets	$ 4	$ 5

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Components Of Inventory [Line Items]
Total inventories	$ 68	$ 72
Natural Gas
Components Of Inventory [Line Items]
Total inventories	30	28
Natural Gas Liquids
Components Of Inventory [Line Items]
Total inventories	$ 38	$ 44

Inventories - Additional Inform

Inventories - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Lower of cost or market adjustment	$ 2	$ 3	$ 8

Property, Plant and Equipment -

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 14,532	$ 14,367
Accumulated depreciation	(5,549)	(5,298)
Property, plant and equipment, net	8,983	9,069
Gathering and transmission systems
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8,473	8,560
Gathering and transmission systems | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	20 years
Gathering and transmission systems | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	50 years
Processing, storage and terminal facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,128	5,134
Processing, storage and terminal facilities | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	35 years
Processing, storage and terminal facilities | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	60 years
Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 557	502
Other | Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	3 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	30 years
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 374	$ 171

Property, Plant and Equipment61

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Interest capitalized on construction projects	$ 7	$ 1	$ 32
Depreciation expense	$ 367	$ 366	$ 358

Property, Plant and Equipment P

Property, Plant and Equipment Property, Plant and Equipment - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment - Asset Retirement Obligations [Abstract]
Asset Retirement Obligation	$ 126	$ 124	$ 120
Accretion Expense	8	7	$ 7
Asset Retirement Obligation, Revision of Estimate	$ (6)	$ (3)

Goodwill and Intangible Asset63

Goodwill and Intangible Assets - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Roll Forward]
Balance, beginning of period	$ 236	$ 242
Dispositions of Goodwill	5	6
Balance, end of period	231	236
Gathering and Processing
Goodwill [Roll Forward]
Balance, beginning of period	164	170
Dispositions of Goodwill	5	6
Balance, end of period	159	164
Logistics and Marketing
Goodwill [Roll Forward]
Balance, beginning of period	72	72
Dispositions of Goodwill	0	0
Balance, end of period	$ 72	$ 72
Wholesale Propane Logistics [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	5.00%
Goodwill [Roll Forward]
Balance, end of period	$ 37

Goodwill and Intangible Asset64

Goodwill and Intangible Assets - Schedule of Finite-Lived Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite Lived Intangible Assets [Line Items]
Gross carrying amount	$ 410	$ 410
Accumulated amortization	(161)	(151)
Accumulated impairment	(143)	(122)
Intangible assets, net	106	137
Amortization expense	$ 10	$ 12	$ 19
Weighted Average
Finite Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	13 years
Minimum
Finite Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	1 year
Maximum
Finite Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	18 years

Goodwill and Intangible Asset65

Goodwill and Intangible Assets - Finite-Lived Intangible Assets, Future Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
2,017	$ 10
2,018	9
2,019	9
2,020	9
2,021	9
Thereafter	60
Intangible assets, net	$ 106	$ 137
Minimum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	1 year
Maximum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	18 years
Weighted Average
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	13 years

Investments In Unconsolidated66

Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 3,050	$ 2,969
DCP Sand Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 648	662
Equity method ownership investment (as percent)	66.67%
Investments in unconsolidated affiliates	$ 1,633	1,507
Discovery Producer Services LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (18)	(20)
Equity method ownership investment (as percent)	40.00%
Investments in unconsolidated affiliates	$ 362	385
DCP Southern Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 145	148
Equity method ownership investment (as percent)	66.67%
Investments in unconsolidated affiliates	$ 739	754
Front Range Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 4	5
Equity method ownership investment (as percent)	33.33%
Investments in unconsolidated affiliates	$ 165	165
Texas Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 3	3
Equity method ownership investment (as percent)	10.00%
Investments in unconsolidated affiliates	$ 90	93
Panola Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	15.00%
Investments in unconsolidated affiliates	$ 24	25
Mont Belvieu Enterprise Fractionator
Schedule of Equity Method Investments [Line Items]
Equity method ownership investment (as percent)	12.50%
Investments in unconsolidated affiliates	$ 23	23
Mont Belvieu 1 Fractionator
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (1)	(2)
Equity method ownership investment (as percent)	20.00%
Investments in unconsolidated affiliates	$ 10	10
Other
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 4	$ 7

Investments in Unconsolidated67

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	$ 303	$ 282	$ 184
DCP Sand Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	148	110	63
Discovery Producer Services LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	61	73	54
DCP Southern Hills Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	47	44	18
Front Range Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	17	19	17
Texas Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	9	9	8
Mont Belvieu Enterprise Fractionator
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	13	16	15
Mont Belvieu 1 Fractionator
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	6	9	9
Other
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated affiliates	$ 2	$ 2	$ 0

Investments in Unconsolidated68

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 1,397	$ 1,311	$ 1,142
Operating expenses	647	539	541
Net income	$ 747	$ 768	$ 600

Investments in Unconsolidated69

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 244	$ 232
Long-term assets	5,319	5,274
Current liabilities	(196)	(156)
Long-term liabilities	(200)	(205)
Net assets	$ 5,167	$ 5,145

Fair Value Measurement - Financ

Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	$ 156	$ 0
Current Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	30	42
Long- Term Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	3	5
Current Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(76)	(91)
Long- Term Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(15)	(1)
Level 1 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	156	0
Level 1 | Current Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	10	5
Level 1 | Long- Term Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	1	0
Level 1 | Current Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(29)	(11)
Level 1 | Long- Term Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(3)	(1)
Level 2 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	0	0
Level 2 | Current Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	17	28
Level 2 | Long- Term Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	1	0
Level 2 | Current Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(34)	(57)
Level 2 | Long- Term Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(11)	0
Level 3 | Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments	0	0
Level 3 | Current Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	3	9
Level 3 | Long- Term Assets | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	1	5
Level 3 | Current Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(13)	(23)
Level 3 | Long- Term Liabilities | Commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	$ (1)	$ 0

Fair Value Measurement - Conden

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($) $ in Millions	Jan. 03, 2017	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
CME Rule 814 Effective Date	Jan. 3, 2017
Current Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		$ 9	$ 35
Net realized and unrealized gains (losses) included in earnings		14	3
Transfers out of Level 3		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Assets, CME Rule 814 adjustments		7
Settlements		(13)	(29)
Ending balance		3	9
Net unrealized gains (losses) on derivatives still held included in earnings		3	9
Long- Term Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		5	4
Net realized and unrealized gains (losses) included in earnings		1	1
Transfers out of Level 3		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Assets, CME Rule 814 adjustments		5
Settlements		0	0
Ending balance		1	5
Net unrealized gains (losses) on derivatives still held included in earnings		(4)	3
Current Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		(23)	(23)
Net realized and unrealized (losses) gains included in earnings		(44)	(15)
Transfers out of Level 3		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liabilities, CME Rule 814 adjustments		18
Settlements		36	15
Ending balance		(13)	(23)
Net unrealized gains (losses) on derivatives still held included in earnings		(13)	(23)
Long- Term Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance		0	(6)
Net realized and unrealized (losses) gains included in earnings		(3)	6
Transfers out of Level 3		2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liabilities, CME Rule 814 adjustments		0
Settlements		0	0
Ending balance		(1)	0
Net unrealized gains (losses) on derivatives still held included in earnings		$ (1)	$ 6

Fair Value Measurement - Schedu

Fair Value Measurement - Schedule of Valuation Processes (Detail) $ in Millions	Dec. 31, 2017USD ($)$ / gal
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids | Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.20
Level 3 | Market Approach Valuation Technique | Derivative Liabilities | Natural Gas Liquids | Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Liabilities, fair value | $	$ (14)
Forward Curve Range	1.08
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Assets, fair value | $	$ 4
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids | Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.28
Level 3 | Market Approach Valuation Technique | Derivative Assets | Natural Gas Liquids | Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.82
Affiliated Entity | Natural Gas Liquids
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Production Committed To Related Parties, Percent	22.00%

Fair Value Measurement - Carryi

Fair Value Measurement - Carrying Value and Fair Value of Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Total Debt, Carrying Value	$ 4,736	$ 5,430
Total Debt, Fair Value	$ 4,885	$ 5,395

Fair Value Measurement Fair Val

Fair Value Measurement Fair Value Measurement - Schedule of Assets Measured at Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments	$ 48	$ 0	$ 912
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Adjustment	48
Property, Plant and Equipment [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Adjustment	26
Intangible Assets [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Adjustment	21
Investment in unconsolidated affiliate [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Adjustment	$ 1

Debt - Schedule of Long-Term De

Debt - Schedule of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 01, 2017	Dec. 31, 2016
Facility [Line Items]
Fair value adjustments related to interest rate swap fair value hedges	$ 23		$ 24
Unamortized issuance costs	(29)		(23)
Unamortized discount	(12)		(14)
Total debt	4,707		5,407
Current maturities of long-term debt	0		500
Long-term debt	4,707		4,907
Credit Agreement
Facility [Line Items]
Credit Facility	$ 0		$ 195
Weighted-average variable interest rate			2.01%
Senior Notes | Issued November 2012, interest at 2.500% payable semi-annually, due December 2017
Facility [Line Items]
Senior Notes		$ 500	$ 500
Debt interest rate percentage	2.50%	2.50%
Senior Notes | Issued February 2009, interest at 9.750% payable semiannually, due March 2019
Facility [Line Items]
Senior Notes	$ 450		450
Debt interest rate percentage	9.75%
Senior Notes | Issued March 2014, interest at 2.700% payable semi-annually, due April 2019
Facility [Line Items]
Senior Notes	$ 325		325
Debt interest rate percentage	2.70%
Senior Notes | Issued March 2010, interest at 5.350% payable semiannually, due March 2020
Facility [Line Items]
Senior Notes	$ 600		600
Debt interest rate percentage	5.35%
Senior Notes | Issued September 2011, interest at 4.750% payable semiannually, due September 2021
Facility [Line Items]
Senior Notes	$ 500		500
Debt interest rate percentage	4.75%
Senior Notes | Issued March 2012, interest at 4.950% payable semi-annually, due April 2022
Facility [Line Items]
Senior Notes	$ 350		350
Debt interest rate percentage	4.95%
Senior Notes | Issued March 2013, interest at 3.875% payable semi-annually, due March 2023
Facility [Line Items]
Senior Notes	$ 500		500
Debt interest rate percentage	3.875%
Senior Notes | Issued August 2000, interest at 8.125% payable semi-annually, due August 2030
Facility [Line Items]
Senior Notes	$ 300		300
Debt interest rate percentage	8.125%
Senior Notes | Issued October 2006, interest at 6.450% payable semi-annually, due November 2036
Facility [Line Items]
Senior Notes	$ 300		300
Debt interest rate percentage	6.45%
Senior Notes | Issued September 2007, interest at 6.750% payable semi-annually, due September 2037
Facility [Line Items]
Senior Notes	$ 450		450
Debt interest rate percentage	6.75%
Senior Notes | Issued March 2014, interest at 5.600% payable semi-annually, due April 2044
Facility [Line Items]
Senior Notes	$ 400		400
Debt interest rate percentage	5.60%
Junior subordinated notes | Issued May 2013, interest at 5.850% payable semi-annually, due May 2043
Facility [Line Items]
Senior Notes	$ 550		$ 550
Debt interest rate percentage	5.85%

Debt - Additional Information (

Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Letter of credit amount outstanding	$ 13,000,000
Line of Credit Facility, Borrowing Capacity, Description	$ 500,000,000
Interest deferment period	5 years
Credit Agreement
Debt Instrument [Line Items]
Line of credit maximum borrowing capacity	$ 1,400,000,000
Basis spread determined by credit rating	0.45%
Commitment fee percentage	0.30%
Unused capacity under the credit agreement	$ 1,375,000,000
Letter of credit amount outstanding	25,000,000
Debt covenants, maximum borrowing amount	$ 1,375,000,000
Credit Agreement | LIBOR
Debt Instrument [Line Items]
Variable rate basis spread	1.45%
Credit Agreement | Federal Funds Rate
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
Credit Agreement | LIBOR Market Index
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Credit Agreement | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio in event of acquisition	5.50
Credit Agreement | Quarters Ending March 31, 2017 through December 31, 2017 | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5.75
Credit Agreement | Quarter Ending March 31, 2018 | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5.50
Credit Agreement | Quarter Ending June 30, 2018 | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5.25
Credit Agreement | Quarters After June 30, 2018 | Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5

Debt - Future Maturities of Lon

Debt - Future Maturities of Long-Term Debt (Detail) $ in Millions	Dec. 31, 2017USD ($)
Maturities of Long-term Debt [Abstract]
2,018	$ 0
2,019	775
2,020	600
2,021	500
2,022	350
Thereafter	2,500
Total long-term debt	$ 4,725

Risk Management and Hedging A78

Risk Management and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (9)	$ (8)
Collateral, cash deposits	75
Letter of credit amount outstanding	13
Collateral, cash held	18
Letters of credit received	53
Commodity derivatives
Derivative [Line Items]
Derivative contracts that contain credit-risk related contingent features that were in a net liability position (less than)	$ 1
Affiliated Entity | Natural Gas Liquids
Derivative [Line Items]
Percent of NGL production committed	22.00%
Accumulated Net Gain (Loss) from Cash Flow Hedges
Derivative [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (9)	(8)	$ (8)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Commodity derivatives
Derivative [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (6)	$ (6)	$ (6)

Risk Management and Hedging A79

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity derivatives - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Offsetting Assets [Line Items]
Gross Amounts of Assets Presented in the Balance Sheet	$ 33	$ 47
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	0
Net Amount	33	47
Offsetting Liabilities [Line Items]
Gross Amounts of Liabilities Presented in the Balance Sheet	(91)	(92)
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	0
Net Amount	$ (91)	$ (92)

Risk Management and Hedging A80

Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Derivative Instruments and Hedges, Current Assets	$ 30	$ 42
Derivative Instruments and Hedges, Assets, Noncurrent	3	5
Derivative Liability [Abstract]
Derivative Instruments and Hedges, Current Liabilities	76	91
Derivative Instruments and Hedges, Liabilities, Noncurrent	15	1
Commodity derivatives | Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Derivative Instruments and Hedges, Current Assets	30	42
Derivative Instruments and Hedges, Assets, Noncurrent	3	5
Derivative Instruments Not Designated as Hedging Instruments, Total Assets, at Fair Value	33	47
Commodity derivatives | Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Derivative Instruments and Hedges, Current Liabilities	76	91
Derivative Instruments and Hedges, Liabilities, Noncurrent	15	1
Derivative Instruments Not Designated as Hedging Instruments, Total Liabilities, at Fair Value	$ 91	$ 92

Risk Management and Hedging A81

Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax (Beginning Balance)	$ (8)
Accumulated Other Comprehensive Income (Loss), Net of Tax (Ending Balance)	(9)
Accumulated Net Gain (Loss) from Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax (Beginning Balance)	(8)
Losses reclassified from AOCI to earnings — effective portion	1
Deficit purchase price under carrying value of the Transaction	(2)
Accumulated Other Comprehensive Income (Loss), Net of Tax (Ending Balance)	(9)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Interest Rate Derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax (Beginning Balance)	(3)
Losses reclassified from AOCI to earnings — effective portion	1
Deficit purchase price under carrying value of the Transaction	(2)
Accumulated Other Comprehensive Income (Loss), Net of Tax (Ending Balance)	(4)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Commodity derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax (Beginning Balance)	(6)
Losses reclassified from AOCI to earnings — effective portion	0
Deficit purchase price under carrying value of the Transaction	0
Accumulated Other Comprehensive Income (Loss), Net of Tax (Ending Balance)	(6)
Accumulated Net Gain (Loss) from Cash Flow Hedges | Foreign Currency Derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax (Beginning Balance)	1
Losses reclassified from AOCI to earnings — effective portion	0
Deficit purchase price under carrying value of the Transaction	0
Accumulated Other Comprehensive Income (Loss), Net of Tax (Ending Balance)	$ 1

Risk Management and Hedging A82

Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Trading and marketing gains, net	$ (40)	$ (23)	$ 119
Derivative Assets Not Designated As Hedging Instruments | Third Party | Commodity derivatives
Derivative [Line Items]
Realized (losses) gains	(12)	116	73
Unrealized (losses) gains	(28)	(139)	46
Trading and marketing gains, net	$ (40)	$ (23)	$ 119

Risk Management and Hedging A83

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	12 Months Ended
	Dec. 31, 2017MMBTUbbl	Dec. 31, 2016MMBTUbbl
Crude Oil
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One | bbl	(2,701,000)	(1,470,000)
Net (Short) Position (Bbls), Year Two | bbl	(631,000)	(251,000)
Net (Short) Position (Bbls), Year Three | bbl	(50,000)	(40,000)
Net (Short) Position (Bbls), Year Four | bbl		(50,000)
Natural Gas
Net Long (Short) Position, MMBtu [Abstract]
Net Long (Short) Position (MMBtu), Year One | MMBTU	(35,977,400)	(44,981,850)
Net Long (Short) Position (MMBtu), Year Two | MMBTU	0	0
Net Long (Short) Position (MMBtu), Year Three | MMBTU	0	0
Net Long (Short) Position (MMBtu), Year Four | MMBTU		0
Natural Gas Liquids
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One | bbl	(19,656,392)	(22,225,821)
Net (Short) Position (Bbls), Year Two | bbl	(2,357,156)	144,805
Net (Short) Position (Bbls), Year Three | bbl	238,548	(2,203)
Net (Short) Position (Bbls), Year Four | bbl		240,000
Natural Gas Basis Swaps
Net Long (Short) Position, MMBtu [Abstract]
Net Long (Short) Position (MMBtu), Year One | MMBTU	3,202,500	6,510,000
Net Long (Short) Position (MMBtu), Year Two | MMBTU	7,177,500	912,500
Net Long (Short) Position (MMBtu), Year Three | MMBTU	3,660,000	0
Net Long (Short) Position (MMBtu), Year Four | MMBTU		0

Partnership Equity and Distri84

Partnership Equity and Distributions - Additional Information (Detail)	Nov. 20, 2017$ / shares	Jan. 01, 2017shares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 01, 2017USD ($)	Dec. 31, 2016USD ($)shares
Partnership Equity And Distribution [Line Items]
Units Sold Under Private Placement Price Per Unit | $ / shares	$ 1,000
Distribution coverage ratio, target			1
Incentive distribution, reduction			$ 40,000,000
Common unitholders, units issued (in shares) | shares			143,309,828			114,749,848
2014 Equity Distribution Agreement
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued (in shares) | shares			0	788,033		0
Proceeds from Issuance of Common Stock				$ 31,000,000
Payments of Stock Issuance Costs				$ 1,000,000
Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Offer Value Of Common Stock Unit Remaining Available For Sale			$ 750,000,000
DCP Midstream, LLC
Partnership Equity And Distribution [Line Items]
Incentive distribution, potential annual reduction (up to)			100,000,000
Incentive distribution potential quarterly reduction			$ 20,000,000
DCP Midstream, LLC | Common Units
Partnership Equity And Distribution [Line Items]
Equity interest issued, number of units (in shares) | shares		28,552,480
DCP Midstream, LLC | General Partner Units
Partnership Equity And Distribution [Line Items]
Equity interest issued, number of units (in shares) | shares		2,550,644
Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 | Senior Notes
Partnership Equity And Distribution [Line Items]
Debt Instrument, Face Amount					$ 500,000,000	$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage			2.50%		2.50%
General Partner
Partnership Equity And Distribution [Line Items]
General Partner Ownership Interest			2.00%
Limited Partners
Partnership Equity And Distribution [Line Items]
Limited Partner Ownership Interest			36.00%
Distribution Stage First [Member]
Partnership Equity And Distribution [Line Items]
Distribution made to Unitholders and General Partner, Per Unit | $ / shares			$ 0.4025
Distribution Stage Second [Member]
Partnership Equity And Distribution [Line Items]
Distribution made to Unitholders and General Partner, Per Unit | $ / shares			$ 0.4375
Incentive Distribution Payments Made And Minimum Distribution Level Percentage			13.00%
Distribution Stage Third [Member]
Partnership Equity And Distribution [Line Items]
Distribution made to Unitholders and General Partner, Per Unit | $ / shares			$ 0.525
Incentive Distribution Payments Made And Minimum Distribution Level Percentage			23.00%
Distribution Stage Thereafter [Member]
Partnership Equity And Distribution [Line Items]
Incentive Distribution Payments Made And Minimum Distribution Level Percentage			48.00%

Partnership Equity and Distri85

Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Per Unit Distribution (in dollars per share)	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 0.78
Total Cash Distribution	$ 155	$ 134	$ 135	$ 121	$ 120	$ 121	$ 121	$ 121	$ 120	$ 121	$ 121	$ 120	$ 545	$ 483	$ 482

Partnership Equity and Distri86

Partnership Equity and Distributions Preferred Series A Distributions (Details) - USD ($)	Dec. 31, 2017	Nov. 20, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distribution Made to Limited Partner [Line Items]
Preferred Units, Issued	500,000	500,000	500,000	0
Proceeds from issuance of Series A preferred limited partner units, net of offering costs		$ 487,000,000	$ 487,000,000	$ 0	$ 0
Preferred Units, Liquidation Preference, Value	$ 1,000		$ 1,000
Preferred Limited Partner Unit Distribution, Annual Per Unit	$ 73.75
Before December 15, 2022 [Member]
Distribution Made to Limited Partner [Line Items]
Preferred Limited Partnership Unit Distribution; Distribution Rate	7.00%
After December 15, 2022 [Member]
Distribution Made to Limited Partner [Line Items]
Preferred Limited Partnership Unit Distribution; Distribution Rate	5.00%

Partnership Equity and Distri87

Partnership Equity and Distributions Preferred Series A Redemption Options (Details)	Dec. 31, 2017$ / shares
Class of Stock [Line Items]
Preferred Limited Partnership Units. Redemption as a Percentage of Liquidation Preference	102.00%
Redemption Prior to December 15, 2022 at premium [Member]
Class of Stock [Line Items]
Preferred Units, Redemption Price Per Share	$ 1,020
Redemption at or subsequent to December 15, 2022 at liquidation preference value [Member]
Class of Stock [Line Items]
Preferred Units, Redemption Price Per Share	1,000
Redemption upon change in control triggering event [Member]
Class of Stock [Line Items]
Preferred Units, Redemption Price Per Share	$ 1,000

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Apr. 28, 2016	Nov. 28, 2005
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 23	$ 18	$ 8
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Estimated Forfeiture Rate	0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Estimated Forfeiture Rate	11.00%
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years
Phantom Share Units (PSUs) | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	1 year
Phantom Share Units (PSUs) | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years
Two Thousand Sixteen Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Units Authorized, in Shares				900,000
Two Thousand Five Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Units Authorized, in Shares					850,000

- Fair Value of Unvested Unit-B

- Fair Value of Unvested Unit-Based Awards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years
Unrecognized Compensation Expense at December 31, 2017 (millions)	$ 7
Maximum vesting percentage	200.00%
Weighted-Average Remaining Vesting (years)	2 years
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Expense at December 31, 2017 (millions)	$ 4
Weighted-Average Remaining Vesting (years)	2 years
Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	1 year
Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years

- Schedule of Units Outstanding

- Schedule of Units Outstanding (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	201,081	207,317	204,368	171,202
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 52.18	$ 46.80	$ 49.85	$ 48.11
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	180,337	132,870	147,540
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 59.43	$ 45.33	$ 47.84
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(16,677)	(3,240)	(17,400)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 51.73	$ 48.62	$ 48.40
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(169,896)	(126,681)	(96,974)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 53.35	$ 50.13	$ 44
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Measurement Date Fair Value, Ending Balance	$ 62.56
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Expected to Vest	188,605
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Expected to Vest	$ 52.13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Measurement Date Fair Value, Expected to Vest	$ 62.99
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	214,735	233,311	208,459	219,363
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 51.98	$ 44.41	$ 48.46	$ 47.89
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	98,628	131,610	111,930
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 76.38	$ 45.31	$ 43.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(18,577)	(8,463)	(29,283)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 50.31	$ 46.27	$ 48.02
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(98,627)	(98,295)	(93,551)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 58.80	$ 54.05	$ 41.02
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Measurement Date Fair Value, Ending Balance	$ 55.61
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Expected to Vest	161,909
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Expected to Vest	$ 54.52
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Measurement Date Fair Value, Expected to Vest	$ 59.37
Two-Thousand And Thirteen [Member] | Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			115.00%
Two-Thousand And Fourteen [Member] | Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		130.00%
Two-Thousand And Fifteen [Member] [Domain] | Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	180.00%

Equity-Based Compensation - Fai

Equity-Based Compensation - Fair Value of Awards Vested (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	169,896	126,681	96,974
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 7	$ 4	$ 3
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 4	$ 5	$ 5
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	98,627	98,295	93,551
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 11	$ 7	$ 4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 7	$ 4	$ 7

Benefits (Details)

Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plan Disclosure [Line Items]
Eligibility minimum age	18 years
Eligibility hours per week	20 hours
Automatic enrollment percentage	6.00%
Defined contribution cost	$ 29	$ 29	$ 32
Minimum
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution percentage	4.00%
Maximum
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution percentage	7.00%

Income Taxes (Details)

Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ (19,000,000)	$ 0
Deferred Tax Liabilities, Net	(29,000,000)	(28,000,000)
Current state income tax expense	(1,000,000)	(2,000,000)	0
Deferred federal income tax expense	0	(22,000,000)	97,000,000
Deferred State and Local Income Tax Expense (Benefit)	(1,000,000)	(3,000,000)	5,000,000
Income tax expense	(2,000,000)	(46,000,000)	$ 102,000,000
Deferred income taxes	$ 29,000,000	28,000,000
Increase (Decrease) In Deferred Tax Assets		$ (58,000,000)
State gross margin tax rate (as percent)	0.75%	0.75%	0.75%

Commitments and Contingent Li94

Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Rent expense	$ 33	$ 37	$ 34
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017	37
2,018	34
2,019	30
2,020	20
2,021	15
Thereafter	28
Total minimum rental payments	164
Other Current Liabilities [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	4	4
Long- Term Liabilities
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 8	$ 9

Restructuring (Details)

Restructuring (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring and Related Cost, Expected Number of Positions Eliminated, Percent	10.00%
Restructuring Cost and Reserve [Line Items]
Restructuring costs		$ 0	$ 13	$ 11
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs			$ 13

Business Segments - Segment Inf

Business Segments - Segment Information (Detail) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting [Abstract]
Number of reportable segments | Segment									2
Segment Reporting Information [Line Items]
Total operating revenues	$ 2,337	$ 2,055	$ 1,949	$ 2,121	$ 1,983	$ 1,823	$ 1,623	$ 1,464	$ 8,462	$ 6,893	$ 7,430
Gross margin									1,577	1,432	1,449
Operating and maintenance expense									(661)	(670)	(732)
Depreciation and amortization expense									(379)	(378)	(377)
General and administrative expense									(290)	(292)	(281)
Asset impairments									(48)	0	(912)
Other income (expense)									(11)	65	(10)
Gain (loss) on sale of assets, net									34	35	42
Restructuring costs									0	13	11
Earnings from unconsolidated affiliates									303	282	184
Interest expense, net									(289)	(321)	(320)
Income tax (expense) benefit									(2)	(46)	102
Net income (loss)	64	(20)	89	101	(39)	89	(21)	65	234	94	(866)
Net income attributable to noncontrolling interests	(4)	0	(1)	0	(5)	0	(1)	0	(5)	(6)	(5)
Net income (loss) attributable to partners	$ 60	$ (20)	$ 88	$ 101	$ (44)	$ 89	$ (22)	$ 65	229	88	(871)
Non-cash derivative mark-to-market									(28)	(139)	46
Non-cash lower of cost or market adjustment									2	3	8
Capital expenditures									375	144	811
Investments in unconsolidated affiliates, net									148	53	64
Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total operating revenues									5,467	4,490	4,910
Gross margin									1,377	1,227	1,213
Operating and maintenance expense									(602)	(611)	(668)
Depreciation and amortization expense									(343)	(344)	(343)
General and administrative expense									(19)	(14)	(22)
Asset impairments									(48)		(876)
Other income (expense)									0	73	(1)
Gain (loss) on sale of assets, net									34	19	42
Restructuring costs										0	0
Earnings from unconsolidated affiliates									60	73	54
Interest expense, net									0	0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									459	423	(601)
Net income attributable to noncontrolling interests									(5)	(6)	(5)
Net income (loss) attributable to partners									454	417	(606)
Non-cash derivative mark-to-market									(24)	(119)	47
Non-cash lower of cost or market adjustment									0	0	0
Capital expenditures									350	107	729
Investments in unconsolidated affiliates, net									1	1	15
Operating Segments | Logistics and Marketing
Segment Reporting Information [Line Items]
Total operating revenues									7,757	6,186	6,487
Gross margin									200	205	236
Operating and maintenance expense									(41)	(43)	(49)
Depreciation and amortization expense									(14)	(15)	(16)
General and administrative expense									(11)	(9)	(11)
Asset impairments									0		(9)
Other income (expense)									(11)	(5)	(8)
Gain (loss) on sale of assets, net									0	16	0
Restructuring costs										0	0
Earnings from unconsolidated affiliates									243	209	130
Interest expense, net									0	0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									366	358	273
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									366	358	273
Non-cash derivative mark-to-market									(4)	(20)	(1)
Non-cash lower of cost or market adjustment									2	3	8
Capital expenditures									3	10	52
Investments in unconsolidated affiliates, net									147	52	49
Other
Segment Reporting Information [Line Items]
Total operating revenues									0	0	0
Gross margin									0	0	0
Operating and maintenance expense									(18)	(16)	(15)
Depreciation and amortization expense									(22)	(19)	(18)
General and administrative expense									(260)	(269)	(248)
Asset impairments									0		(27)
Other income (expense)									0	(3)	(1)
Gain (loss) on sale of assets, net									0	0	0
Restructuring costs										13	11
Earnings from unconsolidated affiliates									0	0	0
Interest expense, net									(289)	(321)	(320)
Income tax (expense) benefit									(2)	(46)	102
Net income (loss)									(591)	(687)	(538)
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									(591)	(687)	(538)
Non-cash derivative mark-to-market									0	0	0
Non-cash lower of cost or market adjustment									0	0	0
Capital expenditures									22	27	30
Investments in unconsolidated affiliates, net									0	0	0
Eliminations
Segment Reporting Information [Line Items]
Total operating revenues									(4,762)	(3,783)	(3,967)
Gross margin									0	0	0
Operating and maintenance expense										0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Asset impairments									0		0
Other income (expense)										0	0
Gain (loss) on sale of assets, net									0	0	0
Restructuring costs										0	0
Earnings from unconsolidated affiliates									0	0	0
Interest expense, net									0	0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									0	0	0
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									0	0	0
Non-cash derivative mark-to-market										0	0
Non-cash lower of cost or market adjustment									0	0	0
Capital expenditures									0	0	0
Investments in unconsolidated affiliates, net									$ 0	$ 0	$ 0

Business Segments - Segment Ass

Business Segments - Segment Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	$ 12,556	$ 12,617
Current assets	1,322	994
Total assets	13,878	13,611
Operating Segments | Gathering and Processing
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	8,943	9,053
Operating Segments | Logistics and Marketing
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	3,348	3,278
Other
Segment Reporting, Asset Reconciling Item [Line Items]
Segment long-term assets	$ 265	$ 286

Supplemental Cash Flow Inform98

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amounts capitalized	$ 290	$ 306	$ 293
Cash paid for income taxes, net of income tax refunds	2	2	3
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accounts payable and accrued liabilities	58	27	35
Other non-cash changes in property, plant and equipment	5	(3)	(19)
Non-Cash Change in Advances To Predecessor	$ 0	$ 0	$ 1,500

Quarterly Financial Data (Una99

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data (Unaudited) [Abstract]
Total operating revenues	$ 2,337	$ 2,055	$ 1,949	$ 2,121	$ 1,983	$ 1,823	$ 1,623	$ 1,464	$ 8,462	$ 6,893	$ 7,430
Operating Income (Loss)	62	(19)	78	101	19	92	(12)	80	222	179	(832)
Net income (loss)	64	(20)	89	101	(39)	89	(21)	65	234	94	(866)
Net income attributable to noncontrolling interests	(4)	0	(1)	0	(5)	0	(1)	0	(5)	(6)	(5)
Net Income (Loss) Attributable to Parent	60	(20)	88	101	(44)	89	(22)	65	229	88	(871)
Net Income (Loss) Allocated to Limited Partners	$ 14	$ (59)	$ 47	$ 59	$ 44	$ 89	$ 14	$ 41	$ 61	$ 188	$ 104
Net income per limited partner unit - basic and diluted (in dollars per share)	$ 0.10	$ (0.41)	$ 0.33	$ 0.41	$ 0.38	$ 0.78	$ 0.12	$ 0.36	$ 0.43	$ 1.64	$ 0.91
Net loss attributable to predecessor operations					$ (119)	$ (31)	$ (67)	$ (7)	$ 0	$ 224	$ 1,099

Condensed Consolidating Fina100

Condensed Consolidating Financial Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017
Parent Guarantor
Condensed Financial Statements, Captions [Line Items]
Ownership interest percentage in subsidiary	100.00%

Condensed Consolidating Fina101

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$ 156	$ 1	$ 3	$ 27
Accounts receivable, net	981	792
Inventories	68	72
Other	117	129
Total current assets	1,322	994
Property, plant and equipment, net	8,983	9,069
Goodwill and intangible assets, net	337	373
Advances receivable — consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0	0
Investments in unconsolidated affiliates	3,050	2,969
Other long-term assets	186	206
Total assets	13,878	13,611
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	1,488	1,123
Current maturities of long-term debt	0	500
Advances payable — consolidated subsidiaries	0	0
Long-term debt	4,707	4,907
Other long-term liabilities	245	228
Total liabilities	6,440	6,758
Commitments and contingent liabilities
Equity:
Net equity	7,417	6,829
Accumulated other comprehensive loss	(9)	(8)
Total partners’ equity	7,408	6,821
Noncontrolling interests	30	32
Total equity	7,438	6,853	7,092	5,215
Total liabilities and equity	13,878	13,611
Reportable Legal Entities | Parent Guarantor
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	2,895	2,953
Investments in unconsolidated affiliates	4,513	3,868
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	7,408	6,821
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Current maturities of long-term debt		0
Advances payable — consolidated subsidiaries	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	0	0
Commitments and contingent liabilities
Equity:
Net equity	7,408	6,821
Accumulated other comprehensive loss	0	0
Total partners’ equity	7,408	6,821
Noncontrolling interests	0	0
Total equity	7,408	6,821
Total liabilities and equity	7,408	6,821
Reportable Legal Entities | Subsidiary Issuer
ASSETS
Cash and cash equivalents	155	0	0	24
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	155	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable — consolidated subsidiaries	1,614	2,760
Investments in unconsolidated affiliates	7,522	6,587
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	9,291	9,347
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	71	72
Current maturities of long-term debt		500
Advances payable — consolidated subsidiaries	0	0
Long-term debt	4,707	4,907
Other long-term liabilities	0	0
Total liabilities	4,778	5,479
Commitments and contingent liabilities
Equity:
Net equity	4,517	3,871
Accumulated other comprehensive loss	(4)	(3)
Total partners’ equity	4,513	3,868
Noncontrolling interests	0	0
Total equity	4,513	3,868
Total liabilities and equity	9,291	9,347
Reportable Legal Entities | Non-Guarantor Subsidiaries
ASSETS
Cash and cash equivalents	1	1	3	3
Accounts receivable, net	981	792
Inventories	68	72
Other	117	129
Total current assets	1,167	994
Property, plant and equipment, net	8,983	9,069
Goodwill and intangible assets, net	337	373
Advances receivable — consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0	0
Investments in unconsolidated affiliates	3,050	2,969
Other long-term assets	186	206
Total assets	13,723	13,611
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	1,417	1,051
Current maturities of long-term debt		0
Advances payable — consolidated subsidiaries	4,509	5,713
Long-term debt	0	0
Other long-term liabilities	245	228
Total liabilities	6,171	6,992
Commitments and contingent liabilities
Equity:
Net equity	7,527	6,592
Accumulated other comprehensive loss	(5)	(5)
Total partners’ equity	7,522	6,587
Noncontrolling interests	30	32
Total equity	7,552	6,619
Total liabilities and equity	13,723	13,611
Consolidating Adjustments
ASSETS
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable — consolidated subsidiaries	(4,509)	(5,713)
Investments in unconsolidated affiliates	(12,035)	(10,455)
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	(16,544)	(16,168)
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Current maturities of long-term debt		0
Advances payable — consolidated subsidiaries	(4,509)	(5,713)
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	(4,509)	(5,713)
Commitments and contingent liabilities
Equity:
Net equity	(12,035)	(10,455)
Accumulated other comprehensive loss	0	0
Total partners’ equity	(12,035)	(10,455)
Noncontrolling interests	0	0
Total equity	(12,035)	(10,455)
Total liabilities and equity	$ (16,544)	$ (16,168)

Condensed Consolidating Fina102

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues:
Sales of natural gas, NGLs and condensate									$ 7,850	$ 6,269	$ 6,779
Transportation, processing and other									652	647	532
Gain (Loss) on Derivative Instruments, Net, Pretax											119
Trading and marketing (losses) gains, net									(40)	(23)	119
Total operating revenues	$ 2,337	$ 2,055	$ 1,949	$ 2,121	$ 1,983	$ 1,823	$ 1,623	$ 1,464	8,462	6,893	7,430
Purchases and related costs									6,885	5,461	5,981
Operating and maintenance expense									661	670	732
Depreciation and amortization expense									379	378	377
General and administrative expense									290	292	281
Impairment of Oil and Gas Properties									48		912
Gain on sale of assets, net									(34)	(35)	(42)
Restructuring costs									0	13	11
Other expense (income), net									11	(65)	10
Total operating costs and expenses									8,240	6,714	8,262
Operating income (loss)	62	(19)	78	101	19	92	(12)	80	222	179	(832)
Interest expense									(289)	(321)	(320)
(Loss) income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									303	282	184
Income (loss) before income taxes									236	140	(968)
Income tax (expense) benefit									(2)	(46)	102
Net income (loss)	64	(20)	89	101	(39)	89	(21)	65	234	94	(866)
Net income attributable to noncontrolling interests	(4)	0	(1)	0	(5)	0	(1)	0	(5)	(6)	(5)
Net income (loss) attributable to partners	$ 60	$ (20)	$ 88	$ 101	$ (44)	$ 89	$ (22)	$ 65	229	88	(871)
Reportable Legal Entities | Parent Guarantor
Operating revenues:
Sales of natural gas, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax											0
Trading and marketing (losses) gains, net									0	0
Total operating revenues									0	0	0
Purchases and related costs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Impairment of Oil and Gas Properties									0		0
Gain on sale of assets, net									0	0	0
Restructuring costs										0	0
Other expense (income), net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense									0	0	0
(Loss) income from consolidated subsidiaries									229	88	(871)
Earnings from unconsolidated affiliates									0	0	0
Income (loss) before income taxes									229	88	(871)
Income tax (expense) benefit									0	0	0
Net income (loss)									229	88	(871)
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									229	88	(871)
Reportable Legal Entities | Subsidiary Issuer
Operating revenues:
Sales of natural gas, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax											0
Trading and marketing (losses) gains, net									0	0
Total operating revenues									0	0	0
Purchases and related costs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Impairment of Oil and Gas Properties									0		0
Gain on sale of assets, net									0	0	0
Restructuring costs										0	0
Other expense (income), net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense									(289)	(321)	(320)
(Loss) income from consolidated subsidiaries									518	409	(551)
Earnings from unconsolidated affiliates									0	0	0
Income (loss) before income taxes									229	88	(871)
Income tax (expense) benefit									0	0	0
Net income (loss)									229	88	(871)
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									229	88	(871)
Reportable Legal Entities | Non-Guarantor Subsidiaries
Operating revenues:
Sales of natural gas, NGLs and condensate									7,850	6,269	6,779
Transportation, processing and other									652	647	532
Gain (Loss) on Derivative Instruments, Net, Pretax											119
Trading and marketing (losses) gains, net									(40)	(23)
Total operating revenues									8,462	6,893	7,430
Purchases and related costs									6,885	5,461	5,981
Operating and maintenance expense									661	670	732
Depreciation and amortization expense									379	378	377
General and administrative expense									290	292	281
Impairment of Oil and Gas Properties									48		912
Gain on sale of assets, net									(34)	(35)	(42)
Restructuring costs										13	11
Other expense (income), net									11	(65)	10
Total operating costs and expenses									8,240	6,714	8,262
Operating income (loss)									222	179	(832)
Interest expense									0	0	0
(Loss) income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									303	282	184
Income (loss) before income taxes									525	461	(648)
Income tax (expense) benefit									(2)	(46)	102
Net income (loss)									523	415	(546)
Net income attributable to noncontrolling interests									(5)	(6)	(5)
Net income (loss) attributable to partners									518	409	(551)
Consolidating Adjustments
Operating revenues:
Sales of natural gas, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax											0
Trading and marketing (losses) gains, net									0	0
Total operating revenues									0	0	0
Purchases and related costs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Impairment of Oil and Gas Properties									0		0
Gain on sale of assets, net									0	0	0
Restructuring costs										0	0
Other expense (income), net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense									0	0	0
(Loss) income from consolidated subsidiaries									(747)	(497)	1,422
Earnings from unconsolidated affiliates									0	0	0
Income (loss) before income taxes									(747)	(497)	1,422
Income tax (expense) benefit									0	0	0
Net income (loss)									(747)	(497)	1,422
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									(747)	(497)	1,422
Intersegment Eliminations [Member]
Operating revenues:
Total operating revenues									(4,762)	(3,783)	(3,967)
Operating and maintenance expense										0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Gain on sale of assets, net									0	0	0
Restructuring costs										0	0
Other expense (income), net										0	0
Interest expense									0	0	0
Earnings from unconsolidated affiliates									0	0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									0	0	0
Net income attributable to noncontrolling interests									0	0	0
Net income (loss) attributable to partners									$ 0	$ 0	$ 0

Condensed Consolidating Fina103

Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ 64	$ (20)	$ 89	$ 101	$ (39)	$ 89	$ (21)	$ 65	$ 234	$ 94	$ (866)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									1	0	1
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									1	0	1
Total comprehensive income (loss)									235	94	(865)
Total comprehensive income attributable to noncontrolling interests									(5)	(6)	(5)
Total comprehensive income attributable to partners									230	88	(870)
Reportable Legal Entities | Parent Guarantor
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									229	88	(871)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									1	0	1
Total other comprehensive income									1	0	1
Total comprehensive income (loss)									230	88	(870)
Total comprehensive income attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									230	88	(870)
Reportable Legal Entities | Subsidiary Issuer
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									229	88	(871)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									1	0	1
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									1	0	1
Total comprehensive income (loss)									230	88	(870)
Total comprehensive income attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									230	88	(870)
Reportable Legal Entities | Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									523	415	(546)
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 (loss)									523	415	(546)
Total comprehensive income attributable to noncontrolling interests									(5)	(6)	(5)
Total comprehensive income attributable to partners									518	409	(551)
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									(747)	(497)	1,422
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									(1)	0	(1)
Total other comprehensive income									(1)	0	(1)
Total comprehensive income (loss)									(748)	(497)	1,421
Total comprehensive income attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									$ (748)	$ (497)	$ 1,421

Condensed Consolidating Fina104

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($)	Nov. 20, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		$ 896,000,000	$ 645,000,000	$ 442,000,000
INVESTING ACTIVITIES:
Intercompany transfers		0	0	0
Capital expenditures		(375,000,000)	(144,000,000)	(811,000,000)
Investments in unconsolidated affiliates, net		(148,000,000)	(53,000,000)	(64,000,000)
Proceeds from sale of assets		132,000,000	163,000,000	164,000,000
Net cash used in investing activities		(391,000,000)	(34,000,000)	(711,000,000)
FINANCING ACTIVITIES:
Intercompany transfers		0	0	0
Proceeds from long-term debt		116,000,000	3,353,000,000	7,216,000,000
Payments of long-term debt		(811,000,000)	(3,628,000,000)	(7,196,000,000)
Payments of commercial paper, net		0	0	(1,012,000,000)
Proceeds from issuance of common limited partners units, net of offering costs		0	0	31,000,000
Net change in advances to predecessor from DCP Midstream, LLC		418,000,000	157,000,000	1,697,000,000
Distributions to limited partners and general partner		(545,000,000)	(483,000,000)	(482,000,000)
Proceeds from issuance of Series A preferred limited partner units, net of offering costs	$ 487,000,000	487,000,000	0	0
Distributions to noncontrolling interests		(7,000,000)	(7,000,000)	(5,000,000)
Proceeds from (Payments for) Other Financing Activities		(8,000,000)	(5,000,000)	(4,000,000)
Net cash (used in) provided by financing activities		(350,000,000)	(613,000,000)	245,000,000
Net change in cash and cash equivalents		155,000,000	(2,000,000)	(24,000,000)
Cash and cash equivalents, beginning of period		1,000,000	3,000,000	27,000,000
Cash and cash equivalents, end of period		156,000,000	1,000,000	3,000,000
Reportable Legal Entities | Parent Guarantor
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		0	0	0
INVESTING ACTIVITIES:
Intercompany transfers		58,000,000	483,000,000	(1,049,000,000)
Capital expenditures		0	0	0
Investments in unconsolidated affiliates, net		0	0	0
Proceeds from sale of assets		0	0	0
Net cash used in investing activities		58,000,000	483,000,000	(1,049,000,000)
FINANCING ACTIVITIES:
Intercompany transfers		0	0	0
Proceeds from long-term debt		0	0	0
Payments of long-term debt		0	0	0
Payments of commercial paper, net				0
Proceeds from issuance of common limited partners units, net of offering costs				31,000,000
Net change in advances to predecessor from DCP Midstream, LLC		0	0	1,500,000,000
Distributions to limited partners and general partner		(545,000,000)	(483,000,000)	(482,000,000)
Proceeds from issuance of Series A preferred limited partner units, net of offering costs		487,000,000
Distributions to noncontrolling interests		0	0	0
Proceeds from (Payments for) Other Financing Activities		0	0	0
Net cash (used in) provided by financing activities		(58,000,000)	(483,000,000)	1,049,000,000
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
Reportable Legal Entities | Subsidiary Issuer
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		(283,000,000)	(305,000,000)	(311,000,000)
INVESTING ACTIVITIES:
Intercompany transfers		1,141,000,000	585,000,000	1,283,000,000
Capital expenditures		0	0	0
Investments in unconsolidated affiliates, net		0	0	0
Proceeds from sale of assets		0	0	0
Net cash used in investing activities		1,141,000,000	585,000,000	1,283,000,000
FINANCING ACTIVITIES:
Intercompany transfers		0	0	0
Proceeds from long-term debt		116,000,000	3,353,000,000	7,216,000,000
Payments of long-term debt		(811,000,000)	(3,628,000,000)	(7,196,000,000)
Payments of commercial paper, net				(1,012,000,000)
Proceeds from issuance of common limited partners units, net of offering costs				0
Net change in advances to predecessor from DCP Midstream, LLC		0	0	0
Distributions to limited partners and general partner		0	0	0
Proceeds from issuance of Series A preferred limited partner units, net of offering costs		0
Distributions to noncontrolling interests		0	0	0
Proceeds from (Payments for) Other Financing Activities		(8,000,000)	(5,000,000)	(4,000,000)
Net cash (used in) provided by financing activities		(703,000,000)	(280,000,000)	(996,000,000)
Net change in cash and cash equivalents		155,000,000	0	(24,000,000)
Cash and cash equivalents, beginning of period		0	0	24,000,000
Cash and cash equivalents, end of period		155,000,000	0	0
Reportable Legal Entities | Non-Guarantor Subsidiaries
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		1,179,000,000	950,000,000	753,000,000
INVESTING ACTIVITIES:
Intercompany transfers		0	0	0
Capital expenditures		(375,000,000)	(144,000,000)	(811,000,000)
Investments in unconsolidated affiliates, net		(148,000,000)	(53,000,000)	(64,000,000)
Proceeds from sale of assets		132,000,000	163,000,000	164,000,000
Net cash used in investing activities		(391,000,000)	(34,000,000)	(711,000,000)
FINANCING ACTIVITIES:
Intercompany transfers		(1,199,000,000)	(1,068,000,000)	(234,000,000)
Proceeds from long-term debt		0	0	0
Payments of long-term debt		0	0	0
Payments of commercial paper, net				0
Proceeds from issuance of common limited partners units, net of offering costs				0
Net change in advances to predecessor from DCP Midstream, LLC		418,000,000	157,000,000	197,000,000
Distributions to limited partners and general partner		0	0	0
Proceeds from issuance of Series A preferred limited partner units, net of offering costs		0
Distributions to noncontrolling interests		(7,000,000)	(7,000,000)	(5,000,000)
Proceeds from (Payments for) Other Financing Activities		0	0	0
Net cash (used in) provided by financing activities		(788,000,000)	(918,000,000)	(42,000,000)
Net change in cash and cash equivalents		0	(2,000,000)	0
Cash and cash equivalents, beginning of period		1,000,000	3,000,000	3,000,000
Cash and cash equivalents, end of period		1,000,000	1,000,000	3,000,000
Consolidating Adjustments
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		0	0	0
INVESTING ACTIVITIES:
Intercompany transfers		(1,199,000,000)	(1,068,000,000)	(234,000,000)
Capital expenditures		0	0	0
Investments in unconsolidated affiliates, net		0	0	0
Proceeds from sale of assets		0	0	0
Net cash used in investing activities		(1,199,000,000)	(1,068,000,000)	(234,000,000)
FINANCING ACTIVITIES:
Intercompany transfers		1,199,000,000	1,068,000,000	234,000,000
Proceeds from long-term debt		0	0	0
Payments of long-term debt		0	0	0
Payments of commercial paper, net				0
Proceeds from issuance of common limited partners units, net of offering costs				0
Net change in advances to predecessor from DCP Midstream, LLC		0	0	0
Distributions to limited partners and general partner		0	0	0
Proceeds from issuance of Series A preferred limited partner units, net of offering costs		0
Distributions to noncontrolling interests		0	0	0
Proceeds from (Payments for) Other Financing Activities		0	0	0
Net cash (used in) provided by financing activities		1,199,000,000	1,068,000,000	234,000,000
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

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 14, 2018	Feb. 07, 2018	Jan. 23, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Incentive distribution, reduction				$ 40
Subsequent Event
Subsequent Event [Line Items]
Distribution declaration date			Jan. 23, 2018
Quarterly distribution (in dollars per share)			$ 0.78
Distribution payable date	Feb. 14, 2018
Distribution record date		Feb. 7, 2018

Uncategorized Items - dpm-20171

Label	Element	Value
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ (3,000,000)
Foreign Currency Derivatives [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ 1,000,000