Adjustments to reconcile net income to net cash provided by operating activities:

$ 233

$ 437

$ 217

120

110

Distributions from unconsolidated affiliates

(173)

(75)

(33)

201

120

Net unrealized losses (gains) on derivative instruments

131

(86)

Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:

Other, net

Accounts receivable

110

(89)

Inventories

Accounts payable

(90)

(67)

Accrued interest

(2)

Other current assets and liabilities

(5)

(2)

Other long-term assets and liabilities

(4)

(2)

Net cash provided by operating activities

650

524

345

(281)

(338)

(363)

(102)

(696)

Acquisition of unconsolidated affiliates

673

(86)

(62)

(151)

(242)

^[1]

(343)

(1,236)

(1,387)

Payments of long-term debt

1,554

719

1,957

(1,429)

(1,988)

(335)

335

Excess purchase price over acquired interests

(7)

(4)

(18)

(85)

Proceeds from issuance of common units, net of offering costs

1,001

1,083

Net change in advances to predecessor from DCP Midstream, LLC

(6)

Distributions to limited partners and general partner

(482)

(420)

(277)

Purchase of additional interest in a subsidiary

(5)

(14)

(24)

(198)

Payments Of Distributions To Parent

(3)

Net cash (used in) provided by financing activities

(330)

725

1,052

(23)

$ 2

$ 25

$ 12

[1]

(a)The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Eagle Ford System [Member]	Eagle Ford System and Commodity Hedge [Member]	Eagle Ford System and NGL Hedge [Member]	Predecessor Equity [Member]	Predecessor Equity [Member] Eagle Ford System [Member]	Limited Partners [Member]	Limited Partners [Member] Eagle Ford System [Member]	Limited Partners [Member] Eagle Ford System and Commodity Hedge [Member]	Limited Partners [Member] Eagle Ford System and NGL Hedge [Member]	General Partner [Member]	General Partner [Member] Eagle Ford System [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Accumulated Other Comprehensive (Loss) Income [Member] Eagle Ford System [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member] Eagle Ford System [Member]
Beginning balance at Dec. 31, 2012	$ 1,636				$ 399		$ 1,063				$ 0		$ (15)		$ 189
Net income	217				25		105				70				17
Other comprehensive (loss) income	4				0								4
Partners Capital Net Change In Parent Advances To Predecessor	11				11
Partners' Capital Account, Acquisitions		$ (395)				$ (395)		$ 0				$ 0		$ 0		$ 0
Partners Capital Account Acquisitions Issuance Of Units		$ 125						$ 125
Excess purchase price over carrying value of acquired net assets			$ (203)	$ (7)					$ (203)	$ (7)
Issuance of common units	1,082						1,082
Distributions to limited partners and general partner	(277)						(215)				(62)
Distributions to noncontrolling interests	(24)														(24)
Contributions from noncontrolling interests	46														46
Contributions from DCP Midstream, LLC	1						1
Distributions to DCP Midstream, LLC	(3)						(3)
Ending balance at Dec. 31, 2013	2,213				40		1,948				8		(11)		228
Net income	437				6		303				114				14
Other comprehensive (loss) income	2				0								2
Partners Capital Net Change In Parent Advances To Predecessor	(6)				(6)
Partners' Capital Account, Acquisitions	(40)				(40)		0				0		0		0
Partners Capital Account Acquisitions Issuance Of Units	225						225
Excess purchase price over carrying value of acquired net assets	(178)						(178)
Issuance of common units	1,002				0		1,002				0		0		0
Distributions to limited partners and general partner	(420)				0		(316)				(104)		0		0
Distributions to noncontrolling interests	(14)				0		0				0		0		(14)
Contributions from noncontrolling interests	3				0		0				0		0		3
Acquisition of additional interest in subsidiary	(198)				0		0				0		0		(198)
Ending balance at Dec. 31, 2014	3,026						2,984				18		(9)		33
Beginning balance at Sep. 30, 2014	3,026				$ 0		2,984				18		(9)		33
Net income	203
Ending balance at Dec. 31, 2014	3,026						2,984				18		(9)		33
Net income	233						104				124				5
Other comprehensive (loss) income	1												1
Issuance of common units	31						31
Distributions to limited partners and general partner	(482)						(358)				(124)
Distributions to noncontrolling interests	(5)														(5)
Contributions from noncontrolling interests	0
Contributions from DCP Midstream, LLC	1						1
Ending balance at Dec. 31, 2015	$ 2,805						$ 2,762				$ 18		$ (8)		$ 33

Consolidated Statements of Changes in Equity (Parenthetical) - shares	1 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consideration financed through issuance of common units			4,497,158
Issuance of common units			20,407,571	24,897,977
Limited Partners [Member]
Consideration financed through issuance of common units			4,497,158
Issuance of common units		793,080	20,407,571	24,897,977
Eagle Ford System [Member]
Consideration financed through issuance of common units	2,789,739
Business Acquisition, Percentage of Voting Interests Acquired	46.67%

Description of Business and Basis of Presentation	12 Months Ended
Description of Business and Basis of Presentation	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we, our or the Partnership, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate; and transporting, storing and selling propane in wholesale markets. We are a Delaware limited partnership that was formed in August 2005. Our partnership includes our Natural Gas Services, NGL Logistics and Wholesale Propane Logistics segments. For additional information regarding these segments, see Note 18 - Business Segments. Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC’s employees provide administrative support to us and operate most of our assets. DCP Midstream, LLC owns approximately 21.4% of us, including limited partner and general partner interests. The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. 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. Transactions between us and other DCP Midstream, LLC operations have been included in the consolidated financial statements as transactions between affiliates.

Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2015

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

Significant Accounting Policies [Text Block]

Summary of Significant Accounting Policies

Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

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

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

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

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



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

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

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

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

______________

(a)

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


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


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

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

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

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

Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

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

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

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

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

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

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

Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence.

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

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


•	significant adverse change in legal factors or business climate;


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


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


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


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


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

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

Unamortized Debt Discount and Expense - Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The discounts 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. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

•

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


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

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

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


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


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


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

•

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

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

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

Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2015, 2014 and 2013. We had significant transactions with affiliates.

Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. There were no environmental liabilities included in the consolidated balance sheet as other current liabilities at December 31, 2015 and $1 million as of December 31, 2014, and other long-term liabilities were $1 million at both December 31, 2015 and 2014.

Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method.

Disclosure of accounting policy for income taxes, which may include its accounting policies for recognizing and measuring deferred tax assets and liabilities and related valuation allowances, recognizing investment tax credits, operating loss carryforwards, tax credit carryforwards, and other carryforwards, methodologies for determining its effective income tax rate and the characterization of interest and penalties in the financial statements.

New Accounting Pronouncements (Notes)	12 Months Ended
New Accounting Pronouncements (Notes)	Dec. 31, 2015
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting period beginning after December 15, 2016, including interim periods within those fiscal years, 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, 2015-11 “Inventory (Topic 330): Simplifying the Measurement of Inventory,” or ASU 2015-11 - In July 2015, the FASB issued ASU 2015-11, which requires an entity to measure in scope inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments apply to inventory that is measured using first-in, first-out (FIFO) or average cost. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, with the option to early adopt as of the beginning of an annual or interim period. We do not expect the adoption of this ASU to have a significant impact on our financial position, results of operations and cash flows. FASB ASU 2015-06 “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions,” or ASU 2015-06 - In April 2015, the FASB issued ASU 2015-06, which specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners, which is typically the earnings per unit measure presented in the financial statements, would not change as a result of the dropdown transaction. This ASU is effective for annual and interim reporting periods beginning after December 15, 2015 and is required to be applied retrospectively. The adoption of this ASU will have no impact on our consolidated results of operations as we have not historically changed previously reported earnings per limited partner unit as a result of dropdown transactions. FASB ASU 2015-03 “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost,” or ASU 2015-03 - In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. The company adopted ASU 2015-03 on December 31, 2015 which required retrospective application to the 2014 consolidated balance sheet. As a result of the adoption, $14 million of debt issuance costs was recorded as a deduction from long-term debt as of December 31, 2015, and $17 million was reclassified from other long-term assets to long-term debt as of December 31, 2014, respectively. FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU is effective for annual reporting periods beginning after December 15, 2015 and we are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification, or ASC, Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as December 15, 2016. We are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position.

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions On January 1, 2015, we entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, we paid $1 million for our interest in the joint venture. The anticipated total consideration of approximately $26 million includes our proportionate share in construction costs for an expansion of the existing Panola NGL pipeline. The Panola NGL pipeline originates in Carthage, Texas and extends approximately 180 miles to Mont Belvieu, Texas. The expansion will extend the Panola NGL pipeline for approximately 60 miles and increase capacity from approximately 50 MBbls/d to 100 MBbls/d. We along with, affiliates of Anadarko Petroleum Corporation, and MarkWest Energy Partners, L.P. each own a 15% interest in Panola. Enterprise owns a 55% interest in Panola and is constructing the expansion and will operate the pipeline. In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016.

Agreements and Transactions with Affiliates

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1500-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4922-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4934-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4926-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Agreements and Transactions with Affiliates

12 Months Ended

Dec. 31, 2015

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. In the event we acquire assets or our business otherwise expands, the annual fee under the Services Agreement is subject to adjustment based on the nature and extent of general and administrative services performed by DCP Midstream, LLC, as well as an annual adjustment based on changes to the Consumer Price Index.

On February 23, 2015, the annual fee payable under the Services Agreement was increased to $71 million, following approval of the increase by the special committee of the board of directors of the General Partner. Our growth, both from organic growth and acquisitions, has resulted in the Partnership becoming a much larger portion of the business of DCP Midstream, LLC. Additionally, our expansion into downstream logistics has required DCP Midstream, LLC to expand its capabilities and provide us with a broader range of services than what was previously provided. As a result, DCP Midstream, LLC initiated a comprehensive review of its costs and the methodology for allocating general and administrative services. The result of this review reflects the level and cost of general and administrative services provided to us by DCP Midstream, LLC as the operator of our assets. The annual fee was effective starting January 1, 2015.

The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC:



	Year Ended December 31,
	2015		2014		2013
	(Millions)
Services Agreement	$	71	$	41	$	29
Other fees — DCP Midstream, LLC	3		6		17
Total — DCP Midstream, LLC	$	74	$	47	$	46

In addition to the fees paid pursuant to the Services Agreement, we incurred allocated expenses, including executive compensation, insurance and internal audit fees with DCP Midstream, LLC of $3 million, $2 million, and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Lucerne 1 plant incurred $1 million in general and administrative expenses directly from DCP Midstream, LLC for the year ended December 31, 2013. The Eagle Ford system incurred $4 million and $14 million in general and administrative expenses directly from DCP Midstream, LLC for the years ended December 31, 2014 and 2013, respectively, before the reallocation of the Eagle Ford system to the Services Agreement on March 31, 2014.

Other Agreements and Transactions with DCP Midstream, LLC

As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.

In conjunction with our acquisition of the O'Connor, Lucerne 1, and Lucerne 2 plants, we entered into long-term fee-based processing agreements with DCP Midstream, LLC pursuant to which DCP Midstream, LLC agreed to pay us (i) a fixed demand charge on a portion of the plants' capacities, and (ii) a throughput fee on all volumes processed for DCP Midstream, LLC at the plants. We report revenues associated with these activities in the consolidated statements of operations as transportation, processing and other to affiliates. Under these agreements in our DJ Basin system we received fees of $71 million, $45 million and $6 million during the years ended December 31, 2015, 2014, and 2013 respectively.

Spectra Energy

Commodity Transactions - We purchase natural gas and other NGL products from, and provide gathering, transportation and other services to, Spectra Energy. Management anticipates continuing to purchase and sell commodities and provide services to Spectra Energy in the ordinary course of business.

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2015		2014		2013
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	958	$	2,179	$	1,830
Transportation, processing and other	$	118	$	92	$	60
Purchases of natural gas, propane and NGLs	$	61	$	194	$	204
Gains from commodity derivative activity, net	$	33	$	118	$	22
Operating and maintenance expense	$	—	$	1	$	1
General and administrative expense	$	74	$	47	$	46
Phillips 66:
Sales of natural gas, propane, NGLs and condensate	$	—	$	1	$	1
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	46	$	77	$	63
Transportation, processing and other	$	—	$	14	$	—
Other income	$	5	$	—	$	—

We had balances with affiliates as follows:



	December 31, 2015		December 31, 2014
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	81	$	163
Accounts payable	$	15	$	24
Unrealized gains on derivative instruments — current	$	32	$	207
Unrealized gains on derivative instruments — long-term	$	9	$	25
Unrealized losses on derivative instruments — current	$	18	$	43
Unrealized losses on derivative instruments — long-term	$	1	$	—
Spectra Energy:
Accounts receivable	$	—	$	1
Accounts payable	$	4	$	3

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

Property, Plant and Equipment [Abstract]

Inventories

12 Months Ended

Dec. 31, 2015

Inventory Disclosure [Abstract]

Inventories

Inventories were as follows:



	December 31, 2015		December 31, 2014
	(Millions)
Natural gas	$	29	$	36
NGLs	14		27
Total inventories	$	43	$	63

We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the consolidated statements of operations. We recognized $8 million, $24 million and $4 million in lower of cost or market adjustments during the years ended December 31, 2015, 2014 and 2013, respectively.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment

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



	Depreciable Life	December 31, 2015			December 31, 2014
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,337		$	2,209
Processing, storage, and terminal facilities	35 — 60 Years	2,327			2,071
Other	3 — 30 Years	64			50
Construction work in progress		122			281
Property, plant and equipment		4,850			4,611
Accumulated depreciation		(1,374		)	(1,264		)
Property, plant and equipment, net		$	3,476		$	3,347

Interest capitalized on construction projects was $6 million, $8 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Depreciation expense was $110 million, $101 million and $87 million for the years ended December 31, 2015 and 2014, respectively.

During the years ended December 31, 2015, 2014 and 2013, we discontinued certain construction projects and wrote off approximately $9 million, $3 million, $8 million, respectively, in construction work in progress to other expense in the consolidated statements of operations.

Asset Retirement Obligations - As of December 31, 2015 and 2014, we had asset retirement obligations of $29 million and $27 million, respectively, included in other long-term liabilities in the consolidated balance sheets. Accretion expense was $2 million, $2 million, and $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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.

Goodwill and Intangible assets Goodwill and Intangible assets

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets Disclosure [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 in 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. During the three months ended June 30, 2015, we determined that continued weak commodity prices caused a change in circumstances warranting an interim impairment test.

Using the fair value approaches described within the Summary of Significant Accounting Policies, we determined that the estimated fair value of our Collbran, Michigan and Southeast Texas reporting units, all of which are included in our Natural Gas Services reporting segment, was less than the carrying amount, primarily due to changes in assumptions related to commodity prices and discount rate.

We then allocated the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. During the second quarter of 2015, we recognized a goodwill impairment based on our best estimate of the impairment resulting from the performance of the hypothetical purchase price allocation which totaled $49 million from our Collbran, Michigan, and Southeast Texas reporting units. We completed the hypothetical purchase price allocation in the third quarter of 2015 and after completing the analysis, there was no remaining fair value to assign to the goodwill of the Collbran reporting unit. As a result, we recorded an additional impairment of $33 million in the third quarter of 2015.

We performed our annual goodwill assessment during the quarter ended September 30, 2015. We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the condensed consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of our annual goodwill assessment.

Our impairment determinations involved significant assumptions and judgments, as discussed within the Summary of Significant Accounting Policies. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. 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 additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. Adverse changes in our business or the overall operating environment such as declines in gas production volumes, loss of significant customers or a further or sustained decrease in commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our operations and cash flows.

The change in carrying amount of goodwill in each of our reporting segments was as follows:



	Year Ended December 31,
	2015							2014
	Gas Services			NGL Logistics		Wholesale Propane Logistics		Gas Services		NGL Logistics		Wholesale Propane Logistics
	(Millions)
Balance, beginning of period	$	82		$	35	$	37	$	82	$	35	$	37
Impairment	(82		)	—		—		—		—		—
Balance, end of period	$	—		$	35	$	37	$	82	$	35	$	37

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,
	2015			2014
	(Millions)
Gross carrying amount	$	164		$	164
Accumulated amortization	(52		)	(44		)
Intangible assets, net	$	112		$	120

We recorded amortization expense of $8 million, $9 million and $8 million for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, the remaining amortization periods ranged from approximately 6 years to 20 years, with a weighted-average remaining period of approximately 15 years.

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(Millions)
2016	$	8
2017	8
2018	8
2019	8
2020	8
Thereafter	72
Total	$	112

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

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2015

Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	December 31, 2015		December 31, 2014
		(Millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	441	$	413
Discovery Producer Services LLC	40%	406		406
DCP Southern Hills Pipeline, LLC	33.33%	318		329
Front Range Pipeline LLC	33.33%	170		169
Texas Express Pipeline LLC	10%	96		98
Mont Belvieu Enterprise Fractionator	12.5%	25		23
Panola Pipeline Company, LLC	15%	19		—
Mont Belvieu 1 Fractionator	20%	11		14
Other	Various	7		7
Total investments in unconsolidated affiliates		$	1,493	$	1,459

Earnings from investments in unconsolidated affiliates were as follows:



		Year Ended December 31,
		2015		2014		2013
	(Millions)
DCP Sand Hills Pipeline, LLC		$	55	$	24	$	—
Discovery Producer Services LLC		55		5		1
Front Range Pipeline LLC		17		2		—
Mont Belvieu Enterprise Fractionator		15		16		14
DCP Southern Hills Pipeline, LLC		14		13		—
Texas Express Pipeline LLC		8		3		(1		)
Mont Belvieu 1 Fractionator		9		12		19
Total earnings from unconsolidated affiliates		$	173	$	75	$	33

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



		Year Ended December 31,
		2015		2014		2013
	(Millions)
Statements of operations (a):
Operating revenue		$	1,172	$	826	$	484
Operating expenses		$	540	$	475	$	298
Net income		$	630	$	349	$	186



	December 31, 2015			December 31, 2014
	(Millions)
Balance sheets (a):
Current assets	$	182		$	207
Long-term assets	5,200			5,157
Current liabilities	(170		)	(200		)
Long-term liabilities	(216		)	(164		)
Net assets	$	4,996		$	5,000

(a) In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016. Accordingly, no activity related to Panola is included in the above tables as of and for the year ended December 31, 2015.

Fair Value Measurement

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 12 - Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.


•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.


•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over-the-counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.

Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment; goodwill; and long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our 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.

For the year ended December 31, 2015, we recognized goodwill impairment of $82 million in our consolidated statements of operations. 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.

The following table presents the financial instruments carried at fair value as of December 31, 2015 and 2014, by consolidated balance sheet caption and by valuation hierarchy, as described above:



	December 31, 2015										December 31, 2014
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	83		$	22	$	105		$	—	$	92		$	138	$	230
Short-term investments (b)	$	2	$	—		$	—	$	2		$	24	$	—		$	—	$	24
Long-term assets:
Commodity derivatives (c)	$	—	$	9		$	—	$	9		$	—	$	21		$	18	$	39
Current liabilities:
Commodity derivatives (d)	$	—	$	(18	)	$	—	$	(18	)	$	—	$	(43	)	$	—	$	(43	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(1	)	$	—	$	(1	)	$	—	$	—		$	—	$	—


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


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


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


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


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

Changes in Levels 1 and 2 Fair Value Measurements

The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the years ended December 31, 2015 and 2014, there were no transfers into or out of Level 1 and Level 2 of the fair value hierarchy.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our 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 Assets			Long- Term Assets			Current Liabilities		Long- Term Liabilities
	(Millions)
Year ended December 31, 2015 (a):
Beginning balance	$	138		$	18		$	—	$	—
Net unrealized gains (losses) included in earnings (b)	29			(18		)	—		—
Settlements	(145		)	—			—		—
Ending balance	$	22		$	—		$	—	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	21		$	(18	)	$	—	$	—
Year ended December 31, 2014 (a):
Beginning balance	$	65		$	75		$	—	$	—
Net unrealized gains (losses) included in earnings (b)	150			(57		)	—		—
Settlements	(77		)	—			—		—
Ending balance	$	138		$	18		$	—	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	138		$	(57	)	$	—	$	—


(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2015 and 2014.


(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs

We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.



	December 31, 2015
Product Group	Fair Value		Forward Curve Range
	(Millions)
Assets
NGLs	$	22	$0.16-$0.90	Per gallon

Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.

The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.

We determine the fair value of our fixed-rate Senior Notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our Amended and Restated 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, 2015 and 2014, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, and our Amended and Restated Credit Agreement were as follows:



		December 31, 2015				December 31, 2014
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(Millions)

Senior Notes		$	2,063	$	1,650	$	2,311	$	2,334
Amended and Restated Credit Agreement		$	375	$	375	$	—	$	—

(a) Excludes unamortized issuance costs.

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

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt



	December 31, 2015			December 31, 2014
	(Millions)
Amended and Restated Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.57%, as of December 31, 2015, due May 1, 2019	$	375		$	—
Debt Securities
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015	—			250
Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019	325			325
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			500
Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044	400			400
Unamortized issuance cost	(14		)	(17		)
Unamortized discount	(12		)	(14		)
Total debt	2,424			2,294
Current maturities of long-term debt	—			(250		)
Total long-term debt	$	2,424		$	2,044

Amended and Restated Credit Agreement

On May 1, 2014, we entered into a $1.25 billion amended and restated senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.275% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate, plus 0.50% or the LIBOR Market Index rate, plus 1%, plus (b) an applicable margin of 0.275% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.225% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.

As of December 31, 2015, we had unused borrowing capacity of $874 million, net of letters of credit, under the Amended and Restated Credit Agreement, all of which was available for working capital and other general partnership purposes. Our borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.

The Amended and Restated Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended and Restated Credit Agreement) of not more than 5.0 to 1.0, and following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.

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



	Debt Maturities
	(Millions)
2016	$	—
2017	500
2018	—
2019	700
2020	—
Thereafter	1,250
	2,450
Unamortized issuance cost	(14		)
Unamortized discount	(12		)
Total	$	2,424

Risk Management and Hedging Activities

12 Months Ended

Dec. 31, 2015

Risk Management and Hedging Activities

Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.

Commodity Price Risk

Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2017 with commodity derivative instruments, with the majority of our positions settling through the first quarter of 2016. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL hedges through the first quarter of 2016 are direct product hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity.

Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of operations as a gain or loss on commodity derivative activity.

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.

As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our Amended and Restated Credit Agreement. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2015.

Interest Rate Risk

We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

In conjunction with the issuance of our 4.95% Senior Notes in March 2012, we entered into forward-starting interest rate swap agreements to reduce our exposure to market rate fluctuations prior to issuance. These derivative financial instruments were designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixed the rate we would pay on a portion of our 4.95% Senior Notes, the deferred loss in AOCI will be amortized into interest expense through the maturity of the notes in 2022. The balance in AOCI of these cash flow hedges was in a loss position of $3 million as of December 31, 2015.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.


•	If we were to have an effective event of default under our Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.


•	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 Amended and Restated Credit Agreement. As of December 31, 2015, we were not a party to any agreements that would trigger the cross-default provisions.

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2015, all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2015, we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contracts that contain credit-risk related contingent features were in a net asset position.

Offsetting

Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the 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, 2015								December 31, 2014
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount		Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	114		$	(19	)	$	95	$	269		$	(42	)	$	227
Liabilities:
Commodity derivatives	$	(19	)	$	19		$	—	$	(43	)	$	42		$	(1	)


(a)	There is no cash collateral pledged or received against these positions.

Summarized Derivative Information

The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our 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, 2015 and 2014.



Balance Sheet Line Item	December 31, 2015		December 31, 2014		Balance Sheet Line Item	December 31, 2015			December 31, 2014
	(Millions)					(Millions)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	105	$	230	Unrealized losses on derivative instruments — current	$	(18	)	$	(43	)
Unrealized gains on derivative instruments — long-term	9		39		Unrealized losses on derivative instruments — long-term	(1		)	—
Total	$	114	$	269	Total	$	(19	)	$	(43	)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)		$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion	1			(b)	—			—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)		$	(6	)	$	1	$	(8	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)		$	—		$	—	$	(1	)


(a)	Relates to Discovery, an unconsolidated affiliate.


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

For the year ended December 31, 2015, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our consolidated statements of operations. For the year ended December 31, 2015, no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2014:



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


(a)	Relates to Discovery, an unconsolidated affiliate.


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


(c)	For the year ended December 31, 2014, $1 million of derivative losses were reclassified from AOCI to interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

For the year ended December 31, 2014, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our consolidated statements of operations.

Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:



Commodity Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2015			2014			2013
	(Millions)
Third party:
Realized gains (losses)		$	158		$	(2	)	$	(19	)
Unrealized (losses) gains		(106		)	38			14
Gains (losses) from commodity derivative activity, net		$	52		$	36		$	(5	)
Affiliates:
Realized gains		$	57		$	70		$	73
Unrealized (losses) gains		(24		)	48			(51		)
Gains from commodity derivative activity, net —affiliates		$	33		$	118		$	22


Interest Rate Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2015			2014			2013
	(Millions)
Third party:
Realized losses		$	—		$	(2	)	$	(2	)
Unrealized gains		—			2			2
Interest expense		$	—		$	—		$	—

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below.



	December 31, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net Short Position (Bbls)		Net Long Position (MMBtu)
2016	(1,408,672	)	(15,881,064	)	(813,267	)	2,665,000
2017	—		(7,387,500	)	—		1,800,000

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

Partnership Equity and Distributions

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Partnership Equity and Distributions

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

In April 2015, we filed a new shelf registration statement with the SEC, that became effective upon filing, in order to replace an existing shelf registration statement that was set to expire. As with the prior shelf registration statement, the new shelf registration statement also allows us to issue an unlimited amount of common units and debt securities. We have issued no common units or debt securities under this registration statement.

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, which were used to finance growth opportunities and for general partnership purposes. As of December 31, 2015, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

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

In March 2014, we issued 14,375,000 common units to the public at $48.90 per unit. We received proceeds of $677 million, net of offering costs.

In March 2014, we issued 4,497,158 common units to DCP Midstream, LLC as partial consideration for the March 2014 Transactions.

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

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

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

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

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


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

•provide for the proper conduct of our business;

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


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


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

General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 0.3% and limited partner interest of approximately 1.7% as of December 31, 2015. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

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

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


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


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


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


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

The following table presents our cash distributions paid in 2015 and 2014 and 2013:



Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86
November 14, 2013	$	0.7200	$	82
August 14, 2013	$	0.7100	$	72
May 15, 2013	$	0.7000	$	69
February 14, 2013	$	0.6900	$	54

Net Income or Loss per Limited Partner Unit	12 Months Ended
Net Income or Loss per Limited Partner Unit	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income or Loss per Limited Partner Unit	Net Income or Loss per Limited Partner Unit Our net income or loss is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership agreement. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU. Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under our Long-Term Incentive Plan. The dilutive effect of unit-based awards was 7,038, 10,574 and 19,179 equivalent units during the years ended December 31, 2015, 2014 and 2013 respectively.

Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flow.

Insurance — We have renewed our insurance policies for the 2015-2016 insurance year. We contract with third party insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay. We are jointly insured with DCP Midstream, LLC for a portion of the insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which management believes are common for companies that are of similar size to us and with similar types of operations.

The insurance on Discovery, as placed by Williams Field Service Group LLC, for the 2015-2016 insurance year includes general and excess liability, onshore property damage, including named windstorm and business interruption, and offshore non-wind property and business interruption insurance. We believe offshore named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, high deductibles and low coverage limits. As such, Discovery continues to elect not to purchase offshore named windstorm property and business interruption insurance coverage for the 2015-2016 insurance year.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations and safety standards. In addition, there is increasing focus, from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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

Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, totaled $11 million, $13 million, and $17 million for the years ended December 31, 2015, 2014, and 2014, 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, 2015:



	(Millions)
2016	$	19
2017	17
2018	15
2019	13
2020	10
Thereafter	18
Total minimum rental payments	$	92

Business Segments

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Business Segments

Our operations are located in the United States and are organized into three reporting segments: Natural Gas Services; NGL Logistics; and Wholesale Propane Logistics. Our chief operating decision maker regularly reviews financial information about our operating segments, which are aggregated into the reporting units presented, in deciding how to allocate resources and evaluate performance.

Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing, treating, processing, transporting and storing natural gas, and fractionating NGLs. The segment consists of our Eagle Ford system, East Texas system, Southeast Texas system, Michigan system, Northern Louisiana system, Southern Oklahoma system, Wyoming system, DJ Basin system, 75% interest in the Piceance system and 40% interest in Discovery.

NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of our storage facility in Michigan, the DJ Basin fractionators, 12.5% interest in the Mont Belvieu Enterprise fractionator, 20% interest in the Mont Belvieu 1 fractionator, 10% interest in the Texas Express intrastate pipeline, 15% interest in the Panola intrastate pipeline, 33.33% interests in the Southern Hills, Sand Hills and Front Range pipelines, the Black Lake and Wattenberg interstate pipelines and the Seabreeze and Wilbreeze intrastate pipelines.

Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of propane and other liquefied petroleum gases by pipeline, rail or ship to our terminals that store and deliver the product to distributors. The segment consists of 6 rail terminals, one marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the operations of each segment.

The following tables set forth our segment information:

Year Ended December 31, 2015:



	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	1,618		$	80		$	200		$	—		$	1,898
Gross margin (a)	$	515		$	80		$	57		$	—		$	652
Operating and maintenance expense	(184		)	(20		)	(10		)	—			(214		)
Depreciation and amortization expense	(109		)	(8		)	(3		)	—			(120		)
General and administrative expense	—			—			—			(85		)	(85		)
Goodwill impairment	(82		)	—			—			—			(82		)
Other (expense) income	(8		)	4			—			—			(4		)
Earnings from unconsolidated affiliates	55			118			—			—			173
Interest expense	—			—			—			(92		)	(92		)
Income tax benefit	—			—			—			5			5
Net income (loss)	$	187		$	174		$	44		$	(172	)	$	233
Net income attributable to noncontrolling interests	(5		)	—			—			—			(5		)
Net income (loss) attributable to partners	$	182		$	174		$	44		$	(172	)	$	228
Non-cash derivative mark-to-market (b)	$	(133	)	$	—		$	3		$	(1	)	$	(131	)
Non-cash lower of cost or market adjustments	$	6		$	—		$	2		$	—		$	8
Capital expenditures	$	240		$	37		$	4		$	—		$	281
Investments in unconsolidated affiliates, net	$	15		$	47		$	—		$	—		$	62

Year Ended December 31, 2014:



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

Year Ended December 31, 2013:



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



	December 31,		December 31,
	2015		2014
	(Millions)
Segment long-term assets:
Natural Gas Services	$	4,362	$	3,609
NGL Logistics	679		1,364
Wholesale Propane Logistics	120		118
Other (d)	10		41
Total long-term assets	5,171		5,132
Current assets	306		590
Total assets	$	5,477	$	5,722

(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.


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


(c)	The segment information for the years ended December 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information, similar to the pooling method.


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

Supplemental Cash Flow Elements [Abstract]

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

+ Details

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information



	Year Ended December 31,
	2015			2014		2013
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	86		$	73	$	40
Cash paid for income taxes, net of income tax refunds	$	2		$	2	$	1
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	12		$	43	$	27
Other non-cash changes in property, plant and equipment	$	(8	)	$	4	$	1
Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions	$	—		$	65	$	—
Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$	—		$	160	$	125
Accounts payable related to equity issuance costs	$	—		$	—	$	1

Supplementary Information - Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Supplementary Information - Condensed Consolidating Financial Information

Supplementary Information — Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream Partners, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.



	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	2		$	—		$	2
Accounts receivable, net	—		—			154			—			154
Inventories	—		—			43			—			43
Other	—		—			107			—			107
Total current assets	—		—			306			—			306
Property, plant and equipment, net	—		—			3,476			—			3,476
Goodwill and intangible assets, net	—		—			184			—			184
Advances receivable — consolidated subsidiaries	2,159		2,023			—			(4,182		)	—
Investments in consolidated subsidiaries	613		1,033			—			(1,646		)	—
Investments in unconsolidated affiliates	—		—			1,493			—			1,493
Other long-term assets	—		—			18			—			18
Total assets	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19		$	181		$	—		$	200
Advances payable — consolidated subsidiaries	—		—			4,182			(4,182		)	—
Long-term debt	—		2,424			—			—			2,424
Other long-term liabilities	—		—			48			—			48
Total liabilities	—		2,443			4,411			(4,182		)	2,672
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,772		616			1,038			(1,646		)	2,780
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	2,772		613			1,033			(1,646		)	2,772
Noncontrolling interests	—		—			33			—			33
Total equity	2,772		613			1,066			(1,646		)	2,805
Total liabilities and equity	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477



	Condensed Consolidating Balance Sheet
	December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	24		$	1		$	—		$	25
Accounts receivable, net	—		—			270			—			270
Inventories	—		—			63			—			63
Other	—		—			232			—			232
Total current assets	—		24			566			—			590
Property, plant and equipment, net	—		—			3,347			—			3,347
Goodwill and intangible assets, net	—		—			274			—			274
Advances receivable — consolidated subsidiaries	2,610		1,962			—			(4,572		)	—
Investments in consolidated subsidiaries	383		712			—			(1,095		)	—
Investments in unconsolidated affiliates	—		—			1,459			—			1,459
Other long-term assets	—		—			52			—			52
Total assets	$	2,993	$	2,698		$	5,698		$	(5,667	)	$	5,722
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	271		$	330		$	—		$	601
Advances payable — consolidated subsidiaries	—		—			4,572			(4,572		)	—
Long-term debt	—		2,044			—			—			2,044
Other long-term liabilities	—		—			51			—			51
Total liabilities	—		2,315			4,953			(4,572		)	2,696
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,993		387			717			(1,095		)	3,002
Accumulated other comprehensive loss	—		(4		)	(5		)	—			(9		)
Total partners’ equity	2,993		383			712			(1,095		)	2,993
Noncontrolling interests	—		—			33			—			33
Total equity	2,993		383			745			(1,095		)	3,026
Total liabilities and equity	$	2,993	$	2,698		$	5,698		$	(5,667	)	$	5,722



	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	$	—	$	—		$	1,442		$	—		$	1,442
Transportation, processing and other	—		—			371			—			371
Gains from commodity derivative activity, net	—		—			85			—			85
Total operating revenues	—		—			1,898			—			1,898
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			1,246			—			1,246
Operating and maintenance expense	—		—			214			—			214
Depreciation and amortization expense	—		—			120			—			120
General and administrative expense	—		—			85			—			85
Goodwill impairment	—		—			82			—			82
Other expense	—		—			4			—			4
Total operating costs and expenses	—		—			1,751			—			1,751
Operating income	—		—			147			—			147
Interest expense	—		(92		)	—			—			(92		)
Income from consolidated subsidiaries	228		320			—			(548		)	—
Earnings from unconsolidated affiliates	—		—			173			—			173
Income before income taxes	228		228			320			(548		)	228
Income tax benefit	—		—			5			—			5
Net income	228		228			325			(548		)	233
Net income attributable to noncontrolling interests	—		—			(5		)	—			(5		)
Net income attributable to partners	$	228	$	228		$	320		$	(548	)	$	228



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2015
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	228	$	228	$	325		$	(548	)	$	233
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	229		229		325			(549		)	234
Total comprehensive income attributable to noncontrolling interests	—		—		(5		)	—			(5		)
Total comprehensive income attributable to partners	$	229	$	229	$	320		$	(549	)	$	229



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


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	423	$	423	$	523		$	(932	)	$	437
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		2		—			—			2
Other comprehensive income from consolidated subsidiaries	2		—		—			(2		)	—
Total other comprehensive income	2		2		—			(2		)	2
Total comprehensive income	425		425		523			(934		)	439
Total comprehensive income attributable to noncontrolling interests	—		—		(14		)	—			(14		)
Total comprehensive income attributable to partners	$	425	$	425	$	509		$	(934	)	$	425


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



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


(a)	The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



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


(a)	The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(89	)	$	739		$	—		$	650
INVESTING ACTIVITIES:
Intercompany transfers	451			(60		)	—			(391		)	—
Capital expenditures	—			—			(281		)	—			(281		)
Investments in unconsolidated affiliates	—			—			(62		)	—			(62		)
Net cash provided by (used in) investing activities	451			(60		)	(343		)	(391		)	(343		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(391		)	391			—
Proceeds from long-term debt	—			1,554			—			—			1,554
Payments of long-term debt	—			(1,429		)	—			—			(1,429		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Distributions to limited partners and general partner	(482		)	—			—			—			(482		)
Distributions to noncontrolling interests	—			—			(5		)	—			(5		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash (used in) provided by financing activities	(451		)	125			(395		)	391			(330		)
Net change in cash and cash equivalents	—			(24		)	1			—			(23		)
Cash and cash equivalents, beginning of period	—			24			1			—			25
Cash and cash equivalents, end of period	$	—		$	—		$	2		$	—		$	2



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


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



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


(a)	The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

Description of Business and Basis of Presentation Description of Business and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors.
Business Combinations and Other Purchase of Business Transactions, Policy [Policy Text Block]
Equity Method Investments, Policy [Policy Text Block]	Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Use of Estimates, Policy [Policy Text Block]

Cash and Cash Equivalents, Policy [Policy Text Block]

Allowance for Doubtful Accounts [Policy Text Block]

Inventory, Policy [Policy Text Block]

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

Derivatives, Policy [Policy Text Block]

As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our Amended and Restated Credit Agreement. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.

Interest Rate Risk

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

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

Goodwill and Intangible Assets, Policy [Policy Text Block]

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

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


•	significant adverse change in legal factors or business climate;


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


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


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


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


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

Debt, Policy [Policy Text Block]

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

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

Revenue Recognition, Policy [Policy Text Block]

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

•


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

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

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


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


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


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

•

Major Customers, Policy [Policy Text Block]

Environmental Costs, Policy [Policy Text Block]

Income Tax, Policy [Policy Text Block]

Earnings Per Share, Policy [Policy Text Block]

Fair Value Measurement Fair Value Measurement (Policies)

12 Months Ended

Dec. 31, 2015

Fair Value Measurement, Policy [Policy Text Block]

Determination of Fair Value

•

Valuation Hierarchy


•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.


•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over-the-counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.

Interest Rate Derivative Assets and Liabilities

Nonfinancial Assets and Liabilities

Risk Management and Hedging Activities Derivatives, Methods of Accounting (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
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. Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2017 with commodity derivative instruments, with the majority of our positions settling through the first quarter of 2016. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL hedges through the first quarter of 2016 are direct product hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity. Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of operations as a gain or loss on commodity derivative activity. Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our Amended and Restated Credit Agreement. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions. Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2015. Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

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

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

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

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



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

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

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

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

______________

(a)


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


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

Agreements and Transactions with Affiliates (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Fees Incurred and Other Fees Paid

The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC:



	Year Ended December 31,
	2015		2014		2013
	(Millions)
Services Agreement	$	71	$	41	$	29
Other fees — DCP Midstream, LLC	3		6		17
Total — DCP Midstream, LLC	$	74	$	47	$	46

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2015		2014		2013
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	958	$	2,179	$	1,830
Transportation, processing and other	$	118	$	92	$	60
Purchases of natural gas, propane and NGLs	$	61	$	194	$	204
Gains from commodity derivative activity, net	$	33	$	118	$	22
Operating and maintenance expense	$	—	$	1	$	1
General and administrative expense	$	74	$	47	$	46
Phillips 66:
Sales of natural gas, propane, NGLs and condensate	$	—	$	1	$	1
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	46	$	77	$	63
Transportation, processing and other	$	—	$	14	$	—
Other income	$	5	$	—	$	—

We had balances with affiliates as follows:



	December 31, 2015		December 31, 2014
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	81	$	163
Accounts payable	$	15	$	24
Unrealized gains on derivative instruments — current	$	32	$	207
Unrealized gains on derivative instruments — long-term	$	9	$	25
Unrealized losses on derivative instruments — current	$	18	$	43
Unrealized losses on derivative instruments — long-term	$	1	$	—
Spectra Energy:
Accounts receivable	$	—	$	1
Accounts payable	$	4	$	3

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Classification of Property, Plant and Equipment

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



	Depreciable Life	December 31, 2015			December 31, 2014
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,337		$	2,209
Processing, storage, and terminal facilities	35 — 60 Years	2,327			2,071
Other	3 — 30 Years	64			50
Construction work in progress		122			281
Property, plant and equipment		4,850			4,611
Accumulated depreciation		(1,374		)	(1,264		)
Property, plant and equipment, net		$	3,476		$	3,347

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	December 31, 2015		December 31, 2014
		(Millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	441	$	413
Discovery Producer Services LLC	40%	406		406
DCP Southern Hills Pipeline, LLC	33.33%	318		329
Front Range Pipeline LLC	33.33%	170		169
Texas Express Pipeline LLC	10%	96		98
Mont Belvieu Enterprise Fractionator	12.5%	25		23
Panola Pipeline Company, LLC	15%	19		—
Mont Belvieu 1 Fractionator	20%	11		14
Other	Various	7		7
Total investments in unconsolidated affiliates		$	1,493	$	1,459

Earnings from Investments in Unconsolidated Affiliates

Earnings from investments in unconsolidated affiliates were as follows:



		Year Ended December 31,
		2015		2014		2013
	(Millions)
DCP Sand Hills Pipeline, LLC		$	55	$	24	$	—
Discovery Producer Services LLC		55		5		1
Front Range Pipeline LLC		17		2		—
Mont Belvieu Enterprise Fractionator		15		16		14
DCP Southern Hills Pipeline, LLC		14		13		—
Texas Express Pipeline LLC		8		3		(1		)
Mont Belvieu 1 Fractionator		9		12		19
Total earnings from unconsolidated affiliates		$	173	$	75	$	33

Equity Method Investment Summarized Financial Information, Statement of Operations

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



		Year Ended December 31,
		2015		2014		2013
	(Millions)
Statements of operations (a):
Operating revenue		$	1,172	$	826	$	484
Operating expenses		$	540	$	475	$	298
Net income		$	630	$	349	$	186

Equity Method Investment Summarized Financial Information, Balance Sheet



	December 31, 2015			December 31, 2014
	(Millions)
Balance sheets (a):
Current assets	$	182		$	207
Long-term assets	5,200			5,157
Current liabilities	(170		)	(200		)
Long-term liabilities	(216		)	(164		)
Net assets	$	4,996		$	5,000

Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Financial Instruments Carried at Fair Value

The following table presents the financial instruments carried at fair value as of December 31, 2015 and 2014, by consolidated balance sheet caption and by valuation hierarchy, as described above:



	December 31, 2015										December 31, 2014
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	83		$	22	$	105		$	—	$	92		$	138	$	230
Short-term investments (b)	$	2	$	—		$	—	$	2		$	24	$	—		$	—	$	24
Long-term assets:
Commodity derivatives (c)	$	—	$	9		$	—	$	9		$	—	$	21		$	18	$	39
Current liabilities:
Commodity derivatives (d)	$	—	$	(18	)	$	—	$	(18	)	$	—	$	(43	)	$	—	$	(43	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(1	)	$	—	$	(1	)	$	—	$	—		$	—	$	—


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


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


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


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

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation



	Commodity Derivative Instruments
	Current Assets			Long- Term Assets			Current Liabilities		Long- Term Liabilities
	(Millions)
Year ended December 31, 2015 (a):
Beginning balance	$	138		$	18		$	—	$	—
Net unrealized gains (losses) included in earnings (b)	29			(18		)	—		—
Settlements	(145		)	—			—		—
Ending balance	$	22		$	—		$	—	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	21		$	(18	)	$	—	$	—
Year ended December 31, 2014 (a):
Beginning balance	$	65		$	75		$	—	$	—
Net unrealized gains (losses) included in earnings (b)	150			(57		)	—		—
Settlements	(77		)	—			—		—
Ending balance	$	138		$	18		$	—	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	138		$	(57	)	$	—	$	—


(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2015 and 2014.


(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Schedule of Valuation Processes



	December 31, 2015
Product Group	Fair Value		Forward Curve Range
	(Millions)
Assets
NGLs	$	22	$0.16-$0.90	Per gallon

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

As of December 31, 2015 and 2014, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, and our Amended and Restated Credit Agreement were as follows:



		December 31, 2015				December 31, 2014
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(Millions)

Senior Notes		$	2,063	$	1,650	$	2,311	$	2,334
Amended and Restated Credit Agreement		$	375	$	375	$	—	$	—

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Debt



	December 31, 2015			December 31, 2014
	(Millions)
Amended and Restated Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.57%, as of December 31, 2015, due May 1, 2019	$	375		$	—
Debt Securities
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015	—			250
Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019	325			325
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			500
Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044	400			400
Unamortized issuance cost	(14		)	(17		)
Unamortized discount	(12		)	(14		)
Total debt	2,424			2,294
Current maturities of long-term debt	—			(250		)
Total long-term debt	$	2,424		$	2,044

Future Maturities of Long-Term Debt

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



	Debt Maturities
	(Millions)
2016	$	—
2017	500
2018	—
2019	700
2020	—
Thereafter	1,250
	2,450
Unamortized issuance cost	(14		)
Unamortized discount	(12		)
Total	$	2,424

Risk Management and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Gross and Net Amounts of Derivative Instruments

The following summarizes the gross and net amounts of our derivative instruments:



	December 31, 2015								December 31, 2014
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount		Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	114		$	(19	)	$	95	$	269		$	(42	)	$	227
Liabilities:
Commodity derivatives	$	(19	)	$	19		$	—	$	(43	)	$	42		$	(1	)


(a)	There is no cash collateral pledged or received against these positions.

Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value



Balance Sheet Line Item	December 31, 2015		December 31, 2014		Balance Sheet Line Item	December 31, 2015			December 31, 2014
	(Millions)					(Millions)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	105	$	230	Unrealized losses on derivative instruments — current	$	(18	)	$	(43	)
Unrealized gains on derivative instruments — long-term	9		39		Unrealized losses on derivative instruments — long-term	(1		)	—
Total	$	114	$	269	Total	$	(19	)	$	(43	)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)		$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion	1			(b)	—			—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)		$	(6	)	$	1	$	(8	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)		$	—		$	—	$	(1	)


(a)	Relates to Discovery, an unconsolidated affiliate.


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

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015:



	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)		$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion	1			(b)	—			—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)		$	(6	)	$	1	$	(8	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)		$	—		$	—	$	(1	)


(a)	Relates to Discovery, an unconsolidated affiliate.


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

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2014:



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


(a)	Relates to Discovery, an unconsolidated affiliate.


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


(c)	For the year ended December 31, 2014, $1 million of derivative losses were reclassified from AOCI to interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments

The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:



Commodity Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2015			2014			2013
	(Millions)
Third party:
Realized gains (losses)		$	158		$	(2	)	$	(19	)
Unrealized (losses) gains		(106		)	38			14
Gains (losses) from commodity derivative activity, net		$	52		$	36		$	(5	)
Affiliates:
Realized gains		$	57		$	70		$	73
Unrealized (losses) gains		(24		)	48			(51		)
Gains from commodity derivative activity, net —affiliates		$	33		$	118		$	22


Interest Rate Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2015			2014			2013
	(Millions)
Third party:
Realized losses		$	—		$	(2	)	$	(2	)
Unrealized gains		—			2			2
Interest expense		$	—		$	—		$	—

Schedule of Net Long or Short Positions Expected to be Realized



	December 31, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net Short Position (Bbls)		Net Long Position (MMBtu)
2016	(1,408,672	)	(15,881,064	)	(813,267	)	2,665,000
2017	—		(7,387,500	)	—		1,800,000

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

Partnership Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Cash Distribution

The following table presents our cash distributions paid in 2015 and 2014 and 2013:



Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86
November 14, 2013	$	0.7200	$	82
August 14, 2013	$	0.7100	$	72
May 15, 2013	$	0.7000	$	69
February 14, 2013	$	0.6900	$	54

Business Segments (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segment Information

The following tables set forth our segment information:

Year Ended December 31, 2015:



	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	1,618		$	80		$	200		$	—		$	1,898
Gross margin (a)	$	515		$	80		$	57		$	—		$	652
Operating and maintenance expense	(184		)	(20		)	(10		)	—			(214		)
Depreciation and amortization expense	(109		)	(8		)	(3		)	—			(120		)
General and administrative expense	—			—			—			(85		)	(85		)
Goodwill impairment	(82		)	—			—			—			(82		)
Other (expense) income	(8		)	4			—			—			(4		)
Earnings from unconsolidated affiliates	55			118			—			—			173
Interest expense	—			—			—			(92		)	(92		)
Income tax benefit	—			—			—			5			5
Net income (loss)	$	187		$	174		$	44		$	(172	)	$	233
Net income attributable to noncontrolling interests	(5		)	—			—			—			(5		)
Net income (loss) attributable to partners	$	182		$	174		$	44		$	(172	)	$	228
Non-cash derivative mark-to-market (b)	$	(133	)	$	—		$	3		$	(1	)	$	(131	)
Non-cash lower of cost or market adjustments	$	6		$	—		$	2		$	—		$	8
Capital expenditures	$	240		$	37		$	4		$	—		$	281
Investments in unconsolidated affiliates, net	$	15		$	47		$	—		$	—		$	62

Year Ended December 31, 2014:



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

Year Ended December 31, 2013:



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



	December 31,		December 31,
	2015		2014
	(Millions)
Segment long-term assets:
Natural Gas Services	$	4,362	$	3,609
NGL Logistics	679		1,364
Wholesale Propane Logistics	120		118
Other (d)	10		41
Total long-term assets	5,171		5,132
Current assets	306		590
Total assets	$	5,477	$	5,722

(a)


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


(c)	The segment information for the years ended December 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information, similar to the pooling method.


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

Supplementary Information - Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Balance Sheets



	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	2		$	—		$	2
Accounts receivable, net	—		—			154			—			154
Inventories	—		—			43			—			43
Other	—		—			107			—			107
Total current assets	—		—			306			—			306
Property, plant and equipment, net	—		—			3,476			—			3,476
Goodwill and intangible assets, net	—		—			184			—			184
Advances receivable — consolidated subsidiaries	2,159		2,023			—			(4,182		)	—
Investments in consolidated subsidiaries	613		1,033			—			(1,646		)	—
Investments in unconsolidated affiliates	—		—			1,493			—			1,493
Other long-term assets	—		—			18			—			18
Total assets	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19		$	181		$	—		$	200
Advances payable — consolidated subsidiaries	—		—			4,182			(4,182		)	—
Long-term debt	—		2,424			—			—			2,424
Other long-term liabilities	—		—			48			—			48
Total liabilities	—		2,443			4,411			(4,182		)	2,672
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,772		616			1,038			(1,646		)	2,780
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	2,772		613			1,033			(1,646		)	2,772
Noncontrolling interests	—		—			33			—			33
Total equity	2,772		613			1,066			(1,646		)	2,805
Total liabilities and equity	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477



	Condensed Consolidating Balance Sheet
	December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	24		$	1		$	—		$	25
Accounts receivable, net	—		—			270			—			270
Inventories	—		—			63			—			63
Other	—		—			232			—			232
Total current assets	—		24			566			—			590
Property, plant and equipment, net	—		—			3,347			—			3,347
Goodwill and intangible assets, net	—		—			274			—			274
Advances receivable — consolidated subsidiaries	2,610		1,962			—			(4,572		)	—
Investments in consolidated subsidiaries	383		712			—			(1,095		)	—
Investments in unconsolidated affiliates	—		—			1,459			—			1,459
Other long-term assets	—		—			52			—			52
Total assets	$	2,993	$	2,698		$	5,698		$	(5,667	)	$	5,722
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	271		$	330		$	—		$	601
Advances payable — consolidated subsidiaries	—		—			4,572			(4,572		)	—
Long-term debt	—		2,044			—			—			2,044
Other long-term liabilities	—		—			51			—			51
Total liabilities	—		2,315			4,953			(4,572		)	2,696
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,993		387			717			(1,095		)	3,002
Accumulated other comprehensive loss	—		(4		)	(5		)	—			(9		)
Total partners’ equity	2,993		383			712			(1,095		)	2,993
Noncontrolling interests	—		—			33			—			33
Total equity	2,993		383			745			(1,095		)	3,026
Total liabilities and equity	$	2,993	$	2,698		$	5,698		$	(5,667	)	$	5,722

Condensed Income Statement [Table Text Block]



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



	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	$	—	$	—		$	1,442		$	—		$	1,442
Transportation, processing and other	—		—			371			—			371
Gains from commodity derivative activity, net	—		—			85			—			85
Total operating revenues	—		—			1,898			—			1,898
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			1,246			—			1,246
Operating and maintenance expense	—		—			214			—			214
Depreciation and amortization expense	—		—			120			—			120
General and administrative expense	—		—			85			—			85
Goodwill impairment	—		—			82			—			82
Other expense	—		—			4			—			4
Total operating costs and expenses	—		—			1,751			—			1,751
Operating income	—		—			147			—			147
Interest expense	—		(92		)	—			—			(92		)
Income from consolidated subsidiaries	228		320			—			(548		)	—
Earnings from unconsolidated affiliates	—		—			173			—			173
Income before income taxes	228		228			320			(548		)	228
Income tax benefit	—		—			5			—			5
Net income	228		228			325			(548		)	233
Net income attributable to noncontrolling interests	—		—			(5		)	—			(5		)
Net income attributable to partners	$	228	$	228		$	320		$	(548	)	$	228



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


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

Condensed Statement of Comprehensive Income [Table Text Block]



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014 (a)
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	423	$	423	$	523		$	(932	)	$	437
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		2		—			—			2
Other comprehensive income from consolidated subsidiaries	2		—		—			(2		)	—
Total other comprehensive income	2		2		—			(2		)	2
Total comprehensive income	425		425		523			(934		)	439
Total comprehensive income attributable to noncontrolling interests	—		—		(14		)	—			(14		)
Total comprehensive income attributable to partners	$	425	$	425	$	509		$	(934	)	$	425


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



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



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2015
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	228	$	228	$	325		$	(548	)	$	233
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	229		229		325			(549		)	234
Total comprehensive income attributable to noncontrolling interests	—		—		(5		)	—			(5		)
Total comprehensive income attributable to partners	$	229	$	229	$	320		$	(549	)	$	229

Condensed Consolidating Statements of Cash Flows



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(89	)	$	739		$	—		$	650
INVESTING ACTIVITIES:
Intercompany transfers	451			(60		)	—			(391		)	—
Capital expenditures	—			—			(281		)	—			(281		)
Investments in unconsolidated affiliates	—			—			(62		)	—			(62		)
Net cash provided by (used in) investing activities	451			(60		)	(343		)	(391		)	(343		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(391		)	391			—
Proceeds from long-term debt	—			1,554			—			—			1,554
Payments of long-term debt	—			(1,429		)	—			—			(1,429		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Distributions to limited partners and general partner	(482		)	—			—			—			(482		)
Distributions to noncontrolling interests	—			—			(5		)	—			(5		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash (used in) provided by financing activities	(451		)	125			(395		)	391			(330		)
Net change in cash and cash equivalents	—			(24		)	1			—			(23		)
Cash and cash equivalents, beginning of period	—			24			1			—			25
Cash and cash equivalents, end of period	$	—		$	—		$	2		$	—		$	2



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


(a)	The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.



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


(a)	The financial information for the year ended December 31, 2013 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

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

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Accrued Environmental Loss Contingencies, Current		$ 1
Accrued Environmental Loss Contingencies, Noncurrent	$ 1

Acquisitions - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016 mi	Dec. 31, 2015 USD ($) mi MBbls
Panola [Member]
Business Acquisition [Line Items]
Aggregate consideration for acquisition \| $		$ 1
Anticipated consideration to be paid for acquisition \| $		$ 26
Capacity per day \| MBbls		50
Expected capacity per day \| MBbls		100
Business Acquisition, Percentage of Voting Interests Acquired		15.00%
Pipeline Length In Miles \| mi		180
Other JV Partners [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		15.00%
Operator [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		55.00%
Subsequent Event [Member] \| Panola [Member]
Business Acquisition [Line Items]
Pipeline Length In Miles \| mi	60

Agreements and Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC	$ 3	$ 6	$ 17
Transportation, processing and other	371	345	271
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC	3		2
Lucerne 1 [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC			1
Eagle Ford System [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC		4	14
Affiliated Entity [Member] \| DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	118	92	60
Affiliated Entity [Member] \| DJ Basin System [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	$ 71	$ 45	$ 6

Agreements and Transactions with Affiliates - Schedule of Fees Incurred and Other Fees Paid (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Services/Omnibus Agreement	$ 71	$ 41	$ 29
Other fees - DCP Midstream, LLC	3	6	17
Total - DCP Midstream, LLC	85	64	63
Related Party Transaction, Amounts of Transaction	71
Transportation, processing and other	371	345	271
DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC	3		2
DCP Midstream, LLC [Member] \| Affiliated Entity [Member]
Total - DCP Midstream, LLC	74	47	46
Transportation, processing and other	$ 118	92	60
Eagle Ford System [Member]
Other fees - DCP Midstream, LLC		4	$ 14
Maximum [Member] \| DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC		$ 2

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	$ 1,442	$ 3,143	$ 2,763
Transportation, processing and other	371	345	271
Other Operating Income (Expense), Net	4	3	8
Purchases of natural gas, propane and NGLs	1,246	2,795	2,426
Gain (Loss) on Derivative Instruments, Net, Pretax	85	154	17
Operating and maintenance expense	214	216	215
General and administrative expense	85	64	63
Affiliated Entity [Member] \| DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	958	2,179	1,830
Transportation, processing and other	118	92	60
Purchases of natural gas, propane and NGLs	61	194	204
Operating and maintenance expense	0	1	1
General and administrative expense	74	47	46
Affiliated Entity [Member] \| DCP Midstream, LLC [Member] \| Commodity Derivatives [Member]
Related Party Transaction [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	33	118	22
Affiliated Entity [Member] \| Phillips 66 [Member]
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	0	1	1
Affiliated Entity [Member] \| Spectra Energy [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	0	14	0
Other Operating Income (Expense), Net	5	0	0
Purchases of natural gas, propane and NGLs	$ 46	$ 77	$ 63

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Accounts receivable	$ 81	$ 164
Accounts payable	19	27
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Accounts receivable	81	163
Accounts payable	15	24
Unrealized gains on derivative instruments - current	32	207
Unrealized gains on derivative instruments - long-term	9	25
Unrealized losses on derivative instruments - current	18	43
Unrealized losses on derivative instruments - long-term	1	0
Spectra Energy [Member]
Related Party Transaction [Line Items]
Accounts receivable	0	1
Accounts payable	$ 4	$ 3

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Components Of Inventory [Line Items]
Total inventories	$ 43	$ 63
Natural Gas [Member]
Components Of Inventory [Line Items]
Total inventories	29	36
Natural Gas Liquids [Member]
Components Of Inventory [Line Items]
Total inventories	$ 14	$ 27

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 4,850	$ 4,611
Accumulated depreciation		(1,374)	(1,264)
Property, plant and equipment, net		3,476	3,347
Interest Costs Capitalized	$ 2	6	8	$ 11
Depreciation		110	101	$ 87
Gathering and Transmission Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 2,337	2,209
Gathering and Transmission Systems [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		20 years
Gathering and Transmission Systems [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		50 years
Processing, Storage, and Terminal Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 2,327	2,071
Processing, Storage, and Terminal Facilities [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		35 years
Processing, Storage, and Terminal Facilities [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		60 years
Other Energy Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 64	50
Other Energy Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		3 years
Other Energy Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		30 years
Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 122	$ 281

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Interest Costs Capitalized	$ 2	$ 6	$ 8	$ 11
Depreciation		110	101	87
Assets Disposed of by Method Other than Sale, in Period of Disposition, Gain (Loss) on Disposition		(9)	(3)	(8)
Asset Retirement Obligation, Accretion Expense		2	2	$ 1
Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligations, Noncurrent		$ 29	$ 27

Goodwill and Intangible assets Schedule of Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014
Goodwill [Line Items]
Goodwill			$ 72	$ 154
Goodwill, Impairment Loss			82	0	$ 0
Natural Gas Services [Member]
Goodwill [Line Items]
Goodwill			0	82	82	$ 82
Goodwill, Impairment Loss	$ 33	$ 49	82	0
NGL Logistics [Member]
Goodwill [Line Items]
Goodwill			35	35	35	35
Goodwill, Impairment Loss			0	0
Wholesale Propane Logistics [Member]
Goodwill [Line Items]
Goodwill			37	37	$ 37	$ 37
Goodwill, Impairment Loss			$ 0	$ 0

Goodwill and Intangible assets Schedule of Finite-Lived Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
Finite-Lived Intangible Assets, Gross		$ 164	$ 164
Finite-Lived Intangible Assets, Accumulated Amortization	$ (52)	(44)
Intangible assets, net	112	120
Amortization of Intangible Assets	$ 8	$ 9	$ 8

Goodwill and Intangible assets Finite-Lived Intangible Assets, Future Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	$ 8
Finite-Lived Intangible Assets, Amortization Expense, Year Three	8
Finite-Lived Intangible Assets, Amortization Expense, Year Four	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	8
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	72
Intangible assets, net	$ 112	$ 120
Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	6 years
Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	20 years
Weighted Average [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	15 years

Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 1,493	$ 1,459
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 441	413
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Investments in unconsolidated affiliates	$ 406	406
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	$ 318	329
Front Range Pipeline LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	$ 170	169
Texas Express Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Investments in unconsolidated affiliates	$ 96	98
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	12.50%
Investments in unconsolidated affiliates	$ 25	23
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Investments in unconsolidated affiliates	$ 11	14
Panola [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	15.00%
Investments in unconsolidated affiliates	$ 19	0
Other [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage description	Various
Investments in unconsolidated affiliates	$ 7	$ 7

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 173	$ 75	$ 33
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	55	24	0
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	9	12	19
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	14	13	0
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	15	16	14
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	55	5	1
Texas Express [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	8	3	(1)
Front Range [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 17	$ 2	$ 0

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 1,172	$ 826	$ 484
Operating expenses	540	475	298
Net income	$ 630	$ 349	$ 186

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 182	$ 207
Long-term assets	5,200	5,157
Current liabilities	(170)	(200)
Long-term liabilities	(216)	(164)
Net assets	$ 4,996	$ 5,000

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

Dec. 31, 2015

Dec. 31, 2014

Current Assets [Member]

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

Commodity Derivative [Member] | Current Assets [Member]

$ 2

$ 24

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

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

^[1]

105

230

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

Commodity Derivative [Member] | Current Liabilities [Member]

^[2]

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

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

^[3]

(18)

(43)

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

Level 1 [Member] | Current Assets [Member]

^[4]

(1)

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

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

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

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

^[1]

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

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

^[2]

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

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

^[3]

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

Level 2 [Member] | Current Assets [Member]

^[4]

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

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

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

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

^[1]

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

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

^[2]

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

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

^[3]

(18)

(43)

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

Level 3 [Member] | Current Assets [Member]

^[4]

(1)

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

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

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

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

^[1]

138

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

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

^[2]

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

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

^[3]

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

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

^[4]

$ 0

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

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Current Assets [Member]

Net realized and unrealized gains (losses) included in earnings

^[1]

$ 138

$ 65

^[1],[2]

150

^[1]

(145)

(77)

Net unrealized gains still held included in earnings

^[1]

138

^[1],[2]

138

Long-Term Assets [Member]

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

Net realized and unrealized gains (losses) included in earnings

^[1]

^[1],[2]

(18)

(57)

^[1]

Net unrealized gains still held included in earnings

^[1]

^[1],[2]

(18)

(57)

Current Liabilities [Member]

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

Net realized and unrealized (losses) gains included in earnings

^[1]

^[1],[2]

^[1]

Net unrealized gains (losses) still held included in earnings

^[1]

^[1],[2]

Long-Term Liabilities [Member]

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

Net realized and unrealized (losses) gains included in earnings

^[1]

^[1],[2]

^[1]

Net unrealized gains (losses) still held included in earnings

^[1]

^[1],[2]

$ 0

[1]	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2015 and 2014.
[2]	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Fair Value Measurement - Schedule of Valuation Processes (Detail) $ in Millions	Dec. 31, 2015 USD ($) $ / MMBTU $ / gal $ / Gallon	Dec. 31, 2014
Fair Value, Inputs, Level 3 [Member] \| Market Approach Valuation Technique [Member] \| Derivative Financial Instruments, Assets [Member] \| Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Fair Value, Assets \| $	$ 22
Minimum [Member] \| Fair Value, Inputs, Level 3 [Member] \| Market Approach Valuation Technique [Member] \| Derivative Financial Instruments, Assets [Member] \| Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range \| $ / gal	0.16
Maximum [Member] \| Fair Value, Inputs, Level 3 [Member] \| Market Approach Valuation Technique [Member] \| Derivative Financial Instruments, Assets [Member] \| Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range \| $ / Gallon	0.90
Senior Notes, 3.25% Due 2015 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.25%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	2.50%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	5.60%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	4.95%	4.95%
Senior Notes, 3.875% Due 2023 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.875%
Derivative Financial Instruments, Liabilities [Member] \| Minimum [Member] \| Fair Value, Inputs, Level 3 [Member] \| Market Approach Valuation Technique [Member] \| Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.00
Derivative Financial Instruments, Liabilities [Member] \| Maximum [Member] \| Fair Value, Inputs, Level 3 [Member] \| Market Approach Valuation Technique [Member] \| Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.00

Fair Value Measurement - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Goodwill, Impairment Loss			$ 82	$ 0	$ 0
Debt Instrument, Carrying Amount			2,063	2,311
Debt Instrument, Fair Value			$ 1,650	$ 2,334
Senior Notes, 3.875% Due 2023 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			3.875%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			2.50%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			4.95%	4.95%
Senior Notes, 3.25% Due 2015 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			3.25%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			5.60%
Credit Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying value of outstanding balances			$ 375	$ 0
Fair value of outstanding balances			375	0
Natural Gas Services [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Goodwill, Impairment Loss	$ 33	$ 49	$ 82	$ 0

Debt - Schedule of Long-Term Debt (Detail) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Long-term Debt, Current Maturities

$ 0

$ 250

Unamortized Debt Issuance Expense

(14)

(17)

Unamortized discount

(12)

(14)

Total

2,424

2,294

Total long-term debt

2,424

2,044

Senior Notes, 3.875% Due 2023 [Member]

Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]

500

Senior Notes, 2.50% Due 2017 [Member]

400

Senior Notes, 4.95% Due 2022 [Member]

500

Senior Notes, 3.25% Due 2015 [Member]

350

Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]

250

Credit Agreement [Member]

325

Revolving credit facility, weighted-average variable interest rate of 1.57%, as of December 31, 2015, due May 1, 2019

^[1]

$ 375

$ 0

[1]

December 31, 2015 December 31, 2014 (Millions)Amended and Restated Credit Agreement Revolving credit facility, weighted-average variable interest rate of 1.57%, as of December 31, 2015, due May 1, 2019$375 $—Debt Securities Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015— 250Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017500 500Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019325 325Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022350 350Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023500 500Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044400 400Unamortized issuance cost(14) (17)Unamortized discount(12) (14)Total debt2,424 2,294Current maturities of long-term debt— (250)Total long-term debt$2,424 $2,044

Debt - Schedule of Long-Term Debt (Parenthetical) (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Credit Agreement [Member]

Line of credit facility, maturity date

May 01, 2019

Fair value of outstanding balances

^[1]

$ 375

$ 0

Senior Notes, 3.875% Due 2023 [Member]

3.875%

Senior Notes, 2.50% Due 2017 [Member]

Mar. 15, 2023

2.50%

Senior Notes, 4.95% Due 2022 [Member]

Dec. 01, 2017

4.95%

Senior Notes, 3.25% Due 2015 [Member]

Apr. 01, 2022

3.25%

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

Oct. 01, 2015

[1]

Debt - Additional Information (Detail) $ in Millions	12 Months Ended
Debt - Additional Information (Detail) $ in Millions	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Mar. 31, 2013
Debt Instrument [Line Items]
Proceeds from long-term debt	$ 1,554.0	$ 719.0	$ 1,957.0
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 325.0	325.0
Senior notes interest rate percentage	2.70%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 400.0	400.0
Senior notes interest rate percentage	5.60%
Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 500.0	500.0
Senior notes interest rate percentage	3.875%
Maturity date	Mar. 15, 2023
Senior Notes, 2.50% Due 2017 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 500.0	500.0
Senior notes interest rate percentage	2.50%
Maturity date	Dec. 01, 2017
Senior Notes, 4.95% Due 2022 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 350.0	$ 350.0
Senior notes interest rate percentage	4.95%	4.95%
Maturity date	Apr. 01, 2022
Senior Notes, 3.25% Due 2015 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 0.0	$ 250.0
Senior notes interest rate percentage	3.25%
Maturity date	Oct. 01, 2015
Eagle Ford System [Member]
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				46.67%
Eagle Ford System [Member] \| Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		46.67%
Amended and Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,000.0
Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maturity date	May 01, 2019
Unused capacity under the credit agreement	$ 874.0
Basis spread determined by credit rating	0.275%
Commitment fee percentage	0.23%
London Interbank Offered Rate (LIBOR) [Member] \| Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.275%
Federal Funds Effective Swap Rate [Member] \| Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
London Interbank Offered Rate (LIBOR) Market Index [Member] \| Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of credit issued		1.0
Letters of credit outstanding	$ 1.0	$ 1.0
Minimum [Member] \| Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	1.0
Temporary maximum leverage ratio post-acquisition	1.0
Maximum [Member] \| Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	5.0
Temporary maximum leverage ratio post-acquisition	5.5

Debt - Future Maturities of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Maturities of Long-term Debt [Abstract]
2014	$ 0
2015	500
2016	0
2017	700
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Thereafter	1,250
Total principal	2,450
Unamortized Debt Issuance Expense	14	$ 17
Unamortized discount	(12)	$ (14)
Total	$ 2,424

Risk Management and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013	Aug. 31, 2013
Derivative [Line Items]
Accumulated other comprehensive loss	$ (8)	$ (9)
Common unitholders, units issued	114,740,148	113,949,868
Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ (1)
Cash Flow Hedge [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	(8)	$ (9)	$ (9)	$ (11)
Cash Flow Hedge [Member] \| Commodity Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	(6)	(6)	(6)	(6)
Cash Flow Hedge [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	$ (3)	$ (4)	$ (4)	$ (6)
Limited Partner [Member]
Derivative [Line Items]
Common unitholders, units issued		14,375,000		12,650,000	9,000,000
Senior Notes, 4.95% Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.95%	4.95%

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity Derivatives [Member] - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Gross Amounts of Assets Presented in the Balance Sheet

$ 114

$ 269

Amounts Not Offset in the Balance Sheet - Financial Instruments

^[1]

(19)

(42)

Net Amount, Assets

227

Gross Amounts of Liabilities Presented in the Balance Sheet

(19)

(43)

Amounts Not Offset in the Balance Sheet - Financial Instruments

^[1]

Net Amount, Liabilities

$ 0

$ 1

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

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, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	$ 105	$ 230
Unrealized gains on derivative instruments - long-term	9	39
Derivative Liability [Abstract]
Unrealized losses on derivative instruments - long-term	(1)	0
Commodity Derivatives [Member] \| Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	105	230
Unrealized gains on derivative instruments - long-term	9	39
Derivative assets, fair value, total	114	269
Commodity Derivatives [Member] \| Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	18	43
Unrealized losses on derivative instruments - long-term	(1)	0
Derivative liabilities, fair value, total	$ (19)	$ (43)

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

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

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

$ (9)

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

(8)

$ (9)

Cash Flow Hedge [Member]

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

(9)

(11)

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

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

(8)

(9)

(1)

Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]

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

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

(4)

(6)

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

^[1]

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

(3)

(4)

(1)

Cash Flow Hedge [Member] | Commodity Derivatives [Member]

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

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

(6)

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

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

(6)

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

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

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

^[2]

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

^[2]

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

^[2]

$ 1

^[2]

$ 0

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

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

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Commodity Derivatives [Member]
Derivative [Line Items]
Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing	$ 1

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Dec. 31, 2013

Commodity Derivatives [Member]

$ (8)

$ (9)

Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing

(1)

Cash Flow Hedge [Member]

Losses Reclassified From AOCI to Earnings-Effective Portion

(8)

(9)

$ (9)

$ (11)

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

(1)

Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]

Losses Reclassified From AOCI to Earnings-Effective Portion

(3)

(4)

(6)

^[1]

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

(1)

Cash Flow Hedge [Member] | Commodity Derivatives [Member]

Losses Reclassified From AOCI to Earnings-Effective Portion

(6)

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

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

Losses Reclassified From AOCI to Earnings-Effective Portion

^[2]

$ 1

^[2]

$ 1

^[2]

$ 0

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

^[2]

$ 0

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

Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - Derivative Assets Not Designated As Hedging Instruments [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Affiliates [Member] \| Commodity Derivatives [Member]
Derivative [Line Items]
Realized	$ 57	$ 70	$ 73
Unrealized	(24)	48	(51)
(Losses) gains from commodity derivative activity, net	33	118	22
Third Party [Member] \| Commodity Derivatives [Member]
Derivative [Line Items]
Realized	158	(2)	(19)
Unrealized	(106)	38	14
(Losses) gains from commodity derivative activity, net	$ 52	36	(5)
Third Party [Member] \| Interest Rate Derivatives [Member]
Derivative [Line Items]
Realized		(2)	(2)
Unrealized		$ 2	$ 2

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	12 Months Ended
	Dec. 31, 2015 MMBTU bbl	Dec. 31, 2014 MMBTU bbl
Crude Oil [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013 \| bbl		(745,695)
Net (Short) Position (Bbls), 2014 \| bbl		(561,922)
Net (Short) Position (Bbls), 2015 \| bbl	(1,408,672)	0
Net (Short) Position (Bbls), 2016 \| bbl	0
Natural Gas [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013 \| MMBTU		(20,803,975)
Net Long (Short) Position (MMBtu), 2014 \| MMBTU		(5,668,564)
Net Long (Short) Position (MMBtu), 2015 \| MMBTU	(15,881,064)	(6,387,500)
Net Long (Short) Position (MMBtu), 2016 \| MMBTU	(7,387,500)
Natural Gas Liquids [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2013 \| bbl		5,573,570
Net (Short) Position (Bbls), 2014 \| bbl		(813,267)
Net (Short) Position (Bbls), 2015 \| bbl	(813,267)	0
Net (Short) Position (Bbls), 2016 \| bbl	0
Natural Gas Basis Swaps [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2013 \| MMBTU		2,640,000
Net Long (Short) Position (MMBtu), 2014 \| MMBTU		1,690,000
Net Long (Short) Position (MMBtu), 2015 \| MMBTU	2,665,000	0
Net Long (Short) Position (MMBtu), 2016 \| MMBTU	1,800,000

Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 31, 2013
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued		114,740,148	113,949,868
Issuance of common units			20,407,571	24,897,977
Consideration financed through issuance of common units			4,497,158
Partnership deadline for distributions (in days)		45 days
Distribution Stage First [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit		$ 0.4025
Distribution Stage Second [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit		$ 0.4375
Incentive Distribution Payments Made And Minimum Distribution Level Percentage		13.00%
Distribution Stage Third [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit		$ 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%
Sand Hills Pipeline [Member]
Partnership Equity And Distribution [Line Items]
Equity Method Investment, Ownership Percentage		33.33%
Eagle Ford System [Member]
Partnership Equity And Distribution [Line Items]
Consideration financed through issuance of common units	2,789,739
Business Acquisition, Percentage of Voting Interests Acquired	46.67%
General Partner [Member]
Partnership Equity And Distribution [Line Items]
General partner ownership interest		0.00%
Limited partner ownership interest		2.00%
2014 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued		788,033	2,256,066
Proceeds from issuance of common stock		$ 31	$ 119
Offering costs		1	1
Maximum aggregate offering amount			$ 500
Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued				1,839,430
Proceeds from issuance of common stock				$ 87
Offering costs				$ 1
Offer value of common stock remaining available for sale		$ 349
Limited Partners [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued			14,375,000	12,650,000	9,000,000
Issuance of common units		793,080	20,407,571	24,897,977
Price per common unit			$ 48.90	$ 40.63	$ 50.04
Net proceeds			$ 677	$ 494	$ 434
Consideration financed through issuance of common units			4,497,158
2013 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued			3,769,635
Proceeds from issuance of common stock			$ 206
Offering costs			$ 2
Maximum aggregate offering amount				$ 300

Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Partnership Equity And Distribution [Line Items]
Total Cash Distribution (Millions)	$ 482	$ 420	$ 277
November thirteen Two Thousand Fifteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 120
august fourteen Two Thousand Fifteen [Member] [Member] [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
May Fifteen Two Thousand Fifteen [Member] [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
February Thirteen Two Thousand Fifteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 120
November Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.77
Total Cash Distribution (Millions)	$ 117
August Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7575
Total Cash Distribution (Millions)	$ 111
May Fifteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.745
Total Cash Distribution (Millions)	$ 106
February Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7325
Total Cash Distribution (Millions)	$ 86
November 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution		$ 0.72
Total Cash Distribution (Millions)	82
August 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution		0.71
Total Cash Distribution (Millions)	72
May 15, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution		0.7
Total Cash Distribution (Millions)	69
February 14, 2013 [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution		$ 0.69
Total Cash Distribution (Millions)	$ 54
Distribution Stage First [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4025
Distribution Stage Second [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4375
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	13.00%
Distribution Stage Third [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 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%

Equity-Based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
Equity-Based Compensation (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
State Gross Margin Tax Rate	0.75%	0.95%	0.975%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	850,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	$ 1
Allocated Share-based Compensation Expense	$ 1	$ 1	$ 2

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
State Gross Margin Tax Rate	0.75%	0.95%	0.975%
Current State and Local Tax Expense (Benefit)	$ 0	$ 3	$ 3
Deferred State and Local Income Tax Expense (Benefit)	(5)	3	5
Income tax expense	(5)	6	$ 8
Deferred Tax Liabilities, Net, Noncurrent	$ 8	$ 13

Commitments and Contingent Liabilities Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense, Net	$ 11	$ 13	$ 17
Operating Leases, Future Minimum Payments Due, Next Twelve Months	19
Operating Leases, Future Minimum Payments, Due in Two Years	17
Operating Leases, Future Minimum Payments, Due in Three Years	15
Operating Leases, Future Minimum Payments, Due in Four Years	13
Operating Leases, Future Minimum Payments, Due in Five Years	10
Operating Leases, Future Minimum Payments, Due Thereafter	18
Operating Leases, Future Minimum Payments Due	$ 92

Business Segments - Additional Information (Detail)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Mar. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Segment

Project

Dec. 31, 2014

USD ($)

Project

Dec. 31, 2013

USD ($)

Number of reporting segments | Segment

$ 435

$ 465

$ 430

$ 568

$ 881

$ 868

$ 812

$ 1,081

$ 1,898

$ 3,642

$ 3,051

Ownership interest percentage

100.00%

Number of owned and operated rail terminals | Project

Number of owned marine import terminals | Project

Number of leased marine terminals | Project

Pipeline Terminals | Project

$ 652

$ 847

^[1]

625

Depreciation, Depletion and Amortization, Nonproduction

(214)

(216)

(215)

(120)

(110)

(95)

(85)

(64)

(63)

173

(92)

(86)

(52)

(6)

(8)

Net income attributable to noncontrolling interests

(2)

$ 203

116

233

437

217

(4)

(1)

(4)

(10)

(5)

(14)

(17)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

$ 90

$ 71

$ (2)

$ 69

$ 199

$ 116

$ 29

$ 79

228

423

200

(131)

(36)

281

338

363

775

782

Sand Hills Pipeline [Member]

$ 62

151

242

Natural Gas Services [Member]

33.33%

$ 1,618

3,163

2,598

515

756

501

Depreciation, Depletion and Amortization, Nonproduction

(184)

(189)

(184)

(109)

(101)

(87)

Net income attributable to noncontrolling interests

187

469

230

(5)

(14)

(17)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

182

455

213

(133)

(36)

240

297

334

102

696

$ 15

$ 75

$ 133

Colorado [Member]

Ownership interest percentage

75.00%

Discovery Producer Services LLC [Member]

Mont Belvieu 1 Fractionator [Member]

40.00%

Mont Belvieu Enterprise Fractionator [Member]

20.00%

Southern Hills Pipeline [Member]

12.50%

33.33%

Texas Express [Member]

Ownership interest percentage in subsidiary

10.00%

Panola [Member]

15.00%

NGL Logistics [Member]

$ 80

$ 73

Depreciation, Depletion and Amortization, Nonproduction

(20)

(16)

(8)

(7)

(6)

118

Net income attributable to noncontrolling interests

174

119

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

174

119

673

Wholesale Propane Logistics [Member]

109

200

406

380

Depreciation, Depletion and Amortization, Nonproduction

(10)

(11)

(15)

(3)

(2)

Net income attributable to noncontrolling interests

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(3)

(1)

Other [Member]

^[1]

Depreciation, Depletion and Amortization, Nonproduction

(85)

(64)

(63)

(92)

(86)

(52)

(6)

(8)

Net income attributable to noncontrolling interests

(172)

(156)

(123)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(172)

(156)

(123)

(1)

Front Range Pipeline [Member]

$ 0

33.33%

[1]

Business Segments - Segment Information (Detail) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 435

$ 465

$ 430

$ 568

$ 881

$ 868

$ 812

$ 1,081

$ 1,898

$ 3,642

$ 3,051

652

847

^[1]

625

(214)

(216)

(215)

(120)

(110)

(95)

(85)

(64)

(63)

(82)

173

(4)

(3)

(8)

(92)

(86)

(52)

(6)

(8)

Net income attributable to noncontrolling interests

(2)

203

116

233

437

217

(4)

(1)

(4)

(10)

(5)

(14)

(17)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(2)

$ 69

199

$ 116

$ 29

$ 79

228

423

200

(131)

(36)

281

338

363

775

782

151

242

Natural Gas Services [Member]

5,171

5,132

5,171

5,132

Current assets

306

590

306

590

Total assets

5,477

5,722

5,477

5,722

1,618

3,163

2,598

515

756

501

(184)

(189)

(184)

(109)

(101)

(87)

$ (33)

$ (49)

(82)

(8)

(2)

(1)

Net income attributable to noncontrolling interests

187

469

230

(5)

(14)

(17)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

182

455

213

(133)

(36)

240

297

334

102

696

133

4,362

3,609

4,362

3,609

NGL Logistics [Member]

(20)

(16)

(8)

(7)

(6)

118

(1)

(3)

Net income attributable to noncontrolling interests

174

119

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

174

119

673

109

Wholesale Propane Logistics [Member]

679

1,364

679

1,364

200

406

380

(10)

(11)

(15)

(3)

(2)

(4)

Net income attributable to noncontrolling interests

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(3)

(1)

120

118

120

118

Other [Member]

^[1]

(85)

(64)

(63)

(92)

(86)

(52)

(6)

(8)

Net income attributable to noncontrolling interests

(172)

(156)

(123)

Unrealized Gain (Loss) on Derivatives and Commodity Contracts

(172)

(156)

(123)

(1)

$ 0

$ 10

$ 41

$ 10

$ 41

[1]

Business Segments - Segment Information (Parenthetical) (Detail) - Project	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Number of owned and operated rail terminals	6
Number of owned marine import terminals	1
Marine Terminals	1
Pipeline Terminals		1

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$ 86	$ 73	$ 40
Cash paid for income taxes, net of income tax refunds	2	2	1
Property, plant and equipment acquired with accounts payable	12	43	27
Other non-cash additions of property, plant and equipment	(8)	(4)	(1)
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	0	65	0
Non-cash excess purchase price in March 2014 Transactions and March 2013 Eagle Ford system transaction	$ 0	$ 160	$ 125
Noncash Investing and Financing Activities Related Text	0	0	1

Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 435	$ 465	$ 430	$ 568	$ 881	$ 868	$ 812	$ 1,081	$ 1,898	$ 3,642	$ 3,051
Operating Income (Loss)	63	43	(28)	69	198	111	37	108	147	454	244
Net income	94	72	(2)	69	203	116	29	89	233	437	217
Net income attributable to noncontrolling interests	(4)	(1)	0	0	(4)	0	0	(10)	(5)	(14)	(17)
Net Income (Loss) Attributable to Parent	90	71	(2)	69	199	116	29	79	228	423	200
Net Income (Loss) Allocated to Limited Partners	$ 59	$ 40	$ (33)	$ 38	$ 168	$ 86	$ 2	$ 47	$ 104	$ 303	$ 105
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 0.51	$ 0.35	$ (0.29)	$ 0.33	$ 1.48	$ 0.77	$ 0.02	$ 0.50	$ 0.91	$ 2.84	$ 1.34

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

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 2	$ 25	$ 25	$ 12	$ 2
Accounts receivable, net	154	270
Inventories	43	63
Other	107	232
Total current assets	306	590
Property, plant and equipment, net	3,476	3,347
Goodwill and intangible assets, net	184	274
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,493	1,459
Other long-term assets	18	52
Total assets	5,477	5,722
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	200	601
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,424	2,044
Other long-term liabilities	48	51
Total liabilities	$ 2,672	$ 2,696
Commitments and contingent liabilities
Equity:
Net equity	$ 2,780	$ 3,002
Accumulated other comprehensive loss	(8)	(9)
Total partners' equity	2,772	2,993
Noncontrolling interests	33	33
Total equity	2,805	3,026	3,026	2,213	1,636
Total liabilities and equity	5,477	5,722
Parent Guarantor [Member]
ASSETS
Cash and cash equivalents	0	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	2,159	2,610
Investments in consolidated subsidiaries	613	383
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	2,772	2,993
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Advances payable - consolidated subsidiaries	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	$ 0	$ 0
Commitments and contingent liabilities
Equity:
Net equity	$ 2,772	$ 2,993
Accumulated other comprehensive loss	0	0
Total partners' equity	2,772	2,993
Noncontrolling interests	0	0
Total equity	2,772	2,993
Total liabilities and equity	2,772	2,993
Subsidiary Issuer [Member]
ASSETS
Cash and cash equivalents	0	24	24	0	3
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	24
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	2,023	1,962
Investments in consolidated subsidiaries	1,033	712
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	3,056	2,698
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	19	271
Advances payable - consolidated subsidiaries	0	0
Long-term debt	2,424	2,044
Other long-term liabilities	0	0
Total liabilities	$ 2,443	$ 2,315
Commitments and contingent liabilities
Equity:
Net equity	$ 616	$ 387
Accumulated other comprehensive loss	(3)	(4)
Total partners' equity	613	383
Noncontrolling interests	0	0
Total equity	613	383
Total liabilities and equity	3,056	2,698
Non-Guarantor Subsidiaries [Member]
ASSETS
Cash and cash equivalents	2	1	1	12	2
Accounts receivable, net	154	270
Inventories	43	63
Other	107	232
Total current assets	306	566
Property, plant and equipment, net	3,476	3,347
Goodwill and intangible assets, net	184	274
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,493	1,459
Other long-term assets	18	52
Total assets	5,477	5,698
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	181	330
Advances payable - consolidated subsidiaries	4,182	4,572
Long-term debt	0	0
Other long-term liabilities	48	51
Total liabilities	$ 4,411	$ 4,953
Commitments and contingent liabilities
Equity:
Net equity	$ 1,038	$ 717
Accumulated other comprehensive loss	(5)	(5)
Total partners' equity	1,033	712
Noncontrolling interests	33	33
Total equity	1,066	745
Total liabilities and equity	5,477	5,698
Consolidating Adjustments [Member]
ASSETS
Cash and cash equivalents	0	0	$ 0	$ 0	$ (3)
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	(4,182)	(4,572)
Investments in consolidated subsidiaries	(1,646)	(1,095)
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	(5,828)	(5,667)
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Advances payable - consolidated subsidiaries	(4,182)	(4,572)
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	$ (4,182)	$ (4,572)
Commitments and contingent liabilities
Equity:
Net equity	$ (1,646)	$ (1,095)
Accumulated other comprehensive loss	0	0
Total partners' equity	(1,646)	(1,095)
Noncontrolling interests	0	0
Total equity	(1,646)	(1,095)
Total liabilities and equity	$ (5,828)	$ (5,667)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									$ 1,442.0	$ 3,143.0	$ 2,763.0
Transportation, processing and other									371.0	345.0	271.0
Gain (Loss) on Derivative Instruments, Net, Pretax									85.0	154.0	17.0
Total operating revenues	$ 435.0	$ 465.0	$ 430.0	$ 568.0	$ 881.0	$ 868.0	$ 812.0	$ 1,081.0	1,898.0	3,642.0	3,051.0
Purchases of natural gas, propane and NGLs									1,246.0	2,795.0	2,426.0
Operating and maintenance expense									214.0	216.0	215.0
Depreciation and amortization expense									120.0	110.0	95.0
General and administrative expense									85.0	64.0	63.0
Goodwill, Impairment Loss									82.0	0.0	0.0
Other expense (income)									4.0	3.0	8.0
Total operating costs and expenses									1,751.0	3,188.0	2,807.0
Operating Income (Loss)	63.0	43.0	(28.0)	69.0	198.0	111.0	37.0	108.0	147.0	454.0	244.0
Interest expense									(92.0)	(86.0)	(52.0)
Income from consolidated subsidiaries									0.0	0.0	0.0
Earnings from unconsolidated affiliates									173.0	75.0	33.0
Income before income taxes									228.0	443.0	225.0
Income tax expense									5.0	(6.0)	(8.0)
Net income	94.0	72.0	(2.0)	69.0	203.0	116.0	29.0	89.0	233.0	437.0	217.0
Net income attributable to noncontrolling interests	(4.0)	(1.0)	0.0	0.0	(4.0)	0.0	0.0	(10.0)	(5.0)	(14.0)	(17.0)
Net income attributable to partners	$ 90.0	$ 71.0	$ (2.0)	$ 69.0	$ 199.0	$ 116.0	$ 29.0	$ 79.0	228.0	423.0	200.0
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0.0	0.0	0.0
Transportation, processing and other									0.0	0.0	0.0
Gain (Loss) on Derivative Instruments, Net, Pretax									0.0	0.0	0.0
Total operating revenues									0.0	0.0	0.0
Purchases of natural gas, propane and NGLs									0.0	0.0	0.0
Operating and maintenance expense									0.0	0.0	0.0
Depreciation and amortization expense									0.0	0.0	0.0
General and administrative expense									0.0	0.0	0.0
Goodwill, Impairment Loss									0.0
Other expense (income)									0.0	0.0	0.0
Total operating costs and expenses									0.0	0.0	0.0
Operating Income (Loss)									0.0	0.0	0.0
Interest expense									0.0	0.0	0.0
Income from consolidated subsidiaries									228.0	423.0	200.0
Earnings from unconsolidated affiliates									0.0	0.0	0.0
Income before income taxes									228.0	423.0	200.0
Income tax expense									0.0	0.0	0.0
Net income									228.0	423.0	200.0
Net income attributable to noncontrolling interests									0.0	0.0	0.0
Net income attributable to partners									228.0	423.0	200.0
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0.0	0.0	0.0
Transportation, processing and other									0.0	0.0	0.0
Gain (Loss) on Derivative Instruments, Net, Pretax									0.0	0.0	0.0
Total operating revenues									0.0	0.0	0.0
Purchases of natural gas, propane and NGLs									0.0	0.0	0.0
Operating and maintenance expense									0.0	0.0	0.0
Depreciation and amortization expense									0.0	0.0	0.0
General and administrative expense									0.0	0.0	0.0
Goodwill, Impairment Loss									0.0
Other expense (income)									0.0	0.0	0.0
Total operating costs and expenses									0.0	0.0	0.0
Operating Income (Loss)									0.0	0.0	0.0
Interest expense									(92.0)	(86.0)	(52.0)
Income from consolidated subsidiaries									320.0	509.0	252.0
Earnings from unconsolidated affiliates									0.0	0.0	0.0
Income before income taxes									228.0	423.0	200.0
Income tax expense									0.0	0.0	0.0
Net income									228.0	423.0	200.0
Net income attributable to noncontrolling interests									0.0	0.0	0.0
Net income attributable to partners									228.0	423.0	200.0
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									1,442.0	3,143.0	2,763.0
Transportation, processing and other									371.0	345.0	271.0
Gain (Loss) on Derivative Instruments, Net, Pretax									85.0	154.0	17.0
Total operating revenues									1,898.0	3,642.0	3,051.0
Purchases of natural gas, propane and NGLs									1,246.0	2,795.0	2,426.0
Operating and maintenance expense									214.0	216.0	215.0
Depreciation and amortization expense									120.0	110.0	95.0
General and administrative expense									85.0	64.0	63.0
Goodwill, Impairment Loss									82.0
Other expense (income)									4.0	3.0	8.0
Total operating costs and expenses									1,751.0	3,188.0	2,807.0
Operating Income (Loss)									147.0	454.0	244.0
Interest expense									0.0	0.0	0.0
Income from consolidated subsidiaries									0.0	0.0	0.0
Earnings from unconsolidated affiliates									173.0	75.0	33.0
Income before income taxes									320.0	529.0	277.0
Income tax expense									5.0	(6.0)	(8.0)
Net income									325.0	523.0	269.0
Net income attributable to noncontrolling interests									(5.0)	(14.0)	(17.0)
Net income attributable to partners									320.0	509.0	252.0
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0.0	0.0	0.0
Transportation, processing and other									0.0	0.0	0.0
Gain (Loss) on Derivative Instruments, Net, Pretax									0.0	0.0	0.0
Total operating revenues									0.0	0.0	0.0
Purchases of natural gas, propane and NGLs									0.0	0.0	0.0
Operating and maintenance expense									0.0	0.0	0.0
Depreciation and amortization expense									0.0	0.0	0.0
General and administrative expense									0.0	0.0	0.0
Goodwill, Impairment Loss									0.0
Other expense (income)									0.0	0.0	0.0
Total operating costs and expenses									0.0	0.0	0.0
Operating Income (Loss)									0.0	0.0	0.0
Interest expense									0.0	0.0	0.0
Income from consolidated subsidiaries									(548.0)	(932.0)	(452.0)
Earnings from unconsolidated affiliates									0.0	0.0	0.0
Income before income taxes									(548.0)	(932.0)	(452.0)
Income tax expense									0.0	0.0	0.0
Net income									(548.0)	(932.0)	(452.0)
Net income attributable to noncontrolling interests									0.0	0.0	0.0
Net income attributable to partners									$ (548.0)	$ (932.0)	$ (452.0)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net income	$ 94	$ 72	$ (2)	$ 69	$ 203	$ 116	$ 29	$ 89	$ 233	$ 437	$ 217
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									1	2	4
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									1	2	4
Total comprehensive income									234	439	221
Total comprehensive income (loss) attributable to noncontrolling interests									(5)	(14)	(17)
Total comprehensive income attributable to partners									229	425	204
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									228	423	200
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									1	2	4
Total other comprehensive income									1	2	4
Total comprehensive income									229	425	204
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									229	425	204
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									228	423	200
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									1	2	4
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									1	2	4
Total comprehensive income									229	425	204
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									229	425	204
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									325	523	269
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									325	523	269
Total comprehensive income (loss) attributable to noncontrolling interests									(5)	(14)	(17)
Total comprehensive income attributable to partners									320	509	252
Consolidating Adjustments [Member]
Condensed Financial Statements, Captions [Line Items]
Net income									(548)	(932)	(452)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									(1)	(2)	(4)
Total other comprehensive income									(1)	(2)	(4)
Total comprehensive income									(549)	(934)	(456)
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									$ (549)	$ (934)	$ (456)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Net cash (used in) provided by operating activities

$ 650

$ 524

$ 345

Payments for (Proceeds from) Other Investing Activities

(281)

(338)

(363)

(102)

(696)

(673)

(86)

151

242

^[1]

Proceeds from (Payments for) Other Financing Activities

(343)

(1,236)

(1,387)

1,554

719

1,957

1,429

1,988

(335)

335

Excess purchase price over acquired net assets and commodity hedge

(7)

(4)

(18)

(85)

Proceeds from issuance of common units, net of offering cost

1,001

1,083

Excess Purchase Price Over Acquired Assets

(178)

Net change in advances to predecessor from DCP Midstream, LLC

(6)

(482)

(420)

(277)

(5)

(14)

(24)

(198)

Payments Of Distributions To Parent

(482)

(420)

(277)

(3)

Net cash (used in) provided by financing activities

(330)

725

1,052

(23)

Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired

(696)

Parent Guarantor [Member]

Net cash (used in) provided by operating activities

Payments for (Proceeds from) Other Investing Activities

451

(581)

(806)

^[1]

Proceeds from (Payments for) Other Financing Activities

451

(581)

(806)

Excess purchase price over acquired net assets and commodity hedge

Proceeds from issuance of common units, net of offering cost

1,001

1,083

Net change in advances to predecessor from DCP Midstream, LLC

(482)

(420)

(277)

Net cash (used in) provided by financing activities

(451)

581

806

Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired

Subsidiary Issuer [Member]

Net cash (used in) provided by operating activities

(89)

(73)

(45)

Payments for (Proceeds from) Other Investing Activities

(60)

(280)

(258)

^[1]

Proceeds from (Payments for) Other Financing Activities

(60)

(280)

(258)

1,554

719

1,957

1,429

1,988

(335)

335

Excess purchase price over acquired net assets and commodity hedge

(7)

(4)

Proceeds from issuance of common units, net of offering cost

Net change in advances to predecessor from DCP Midstream, LLC

Net cash (used in) provided by financing activities

125

377

300

(24)

(3)

Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired

Non-Guarantor Subsidiaries [Member]

Net cash (used in) provided by operating activities

739

597

387

Payments for (Proceeds from) Other Investing Activities

(281)

(338)

(363)

(102)

(673)

(86)

151

242

^[1]

Proceeds from (Payments for) Other Financing Activities

(343)

(1,236)

(1,387)

(391)

861

1,064

Excess purchase price over acquired net assets and commodity hedge

(18)

(85)

Proceeds from issuance of common units, net of offering cost

Net change in advances to predecessor from DCP Midstream, LLC

(6)

(5)

(14)

(24)

(198)

(3)

Net cash (used in) provided by financing activities

(395)

628

1,010

(11)

Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired

(696)

Consolidating Adjustments [Member]

Net cash (used in) provided by operating activities

Payments for (Proceeds from) Other Investing Activities

(391)

861

1,064

^[1]

Proceeds from (Payments for) Other Financing Activities

(391)

861

1,064

391

(861)

(1,064)

Excess purchase price over acquired net assets and commodity hedge

Proceeds from issuance of common units, net of offering cost

Net change in advances to predecessor from DCP Midstream, LLC

Net cash (used in) provided by financing activities

391

(861)

(1,064)

(3)