Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | May 05, 2017 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 | |
Trading Symbol | DCP | |
Entity Registrant Name | DCP MIDSTREAM, LP | |
Entity Central Index Key | 1,338,065 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 143,302,328 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 176 | $ 1 |
Accounts receivable: | ||
Trade, net of allowance for doubtful accounts of $4 million | 541 | 652 |
Affiliates | 104 | 134 |
Other | 6 | 6 |
Inventories | 64 | 72 |
Unrealized gains on derivative instruments | 31 | 42 |
Other | 58 | 87 |
Total current assets | 980 | 994 |
Property, plant and equipment, net | 9,047 | 9,069 |
Goodwill | 236 | 236 |
Intangible assets, net | 135 | 137 |
Investments in unconsolidated affiliates | 2,988 | 2,969 |
Unrealized gains on derivative instruments | 4 | 5 |
Other long-term assets | 189 | 201 |
Total assets | 13,579 | 13,611 |
Accounts payable: | ||
Trade | 546 | 677 |
Affiliates | 51 | 48 |
Other | 14 | 10 |
Current maturities of long-term debt | 500 | 500 |
Unrealized losses on derivative instruments | 36 | 91 |
Accrued interest | 57 | 72 |
Accrued taxes | 68 | 49 |
Accrued wages and benefits | 25 | 72 |
Capital spending accrual | 20 | 20 |
Other | 73 | 84 |
Total current liabilities | 1,390 | 1,623 |
Long-term debt | 4,709 | 4,907 |
Unrealized losses on derivative instruments | 7 | 1 |
Deferred income taxes | 28 | 28 |
Other long-term liabilities | 195 | 199 |
Total liabilities | 6,329 | 6,758 |
Commitments and contingent liabilities | ||
Equity: | ||
Predecessor equity | 0 | 4,220 |
Limited partners (143,302,328 and 114,749,848 common units issued and outstanding, respectively) | 7,108 | 2,591 |
General partner | 121 | 18 |
Accumulated other comprehensive loss | (9) | (8) |
Total partners’ equity | 7,220 | 6,821 |
Noncontrolling interests | 30 | 32 |
Total equity | 7,250 | 6,853 |
Total liabilities and equity | $ 13,579 | $ 13,611 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Allowance for doubtful accounts | $ 4 | $ 4 |
Common unitholders, units issued (in shares) | 143,302,328 | 114,749,848 |
Common unitholders, units outstanding (in shares) | 143,302,328 | 114,749,848 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating revenues: | ||
Sales of natural gas and NGLs | $ 1,933 | $ 1,294 |
Transportation, processing and other | 157 | 152 |
Trading and marketing gains, net | 31 | 18 |
Total operating revenues | 2,121 | 1,464 |
Operating costs and expenses: | ||
Purchases of natural gas and NGLs | 1,687 | 1,135 |
Operating and maintenance expense | 167 | 179 |
Depreciation and amortization expense | 94 | 95 |
General and administrative expense | 62 | 62 |
Other expense (income), net | 10 | (87) |
Total operating costs and expenses | 2,020 | 1,384 |
Operating income | 101 | 80 |
Earnings from unconsolidated affiliates | 74 | 66 |
Interest expense, net | (73) | (79) |
Income before income taxes | 102 | 67 |
Income tax expense | (1) | (2) |
Net income | 101 | 65 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 101 | 65 |
Net loss attributable to predecessor operations | 0 | 7 |
General partner’s interest in net income | (42) | (31) |
Net income allocable to limited partners | $ 59 | $ 41 |
Net income per limited partner unit - basic and diluted (in dollars per share) | $ 0.41 | $ 0.36 |
Weighted-average limited partner units outstanding - basic (in shares) | 143.3 | 114.7 |
Weighted-average limited partner units outstanding - diluted (in shares) | 143.3 | 114.7 |
Third Party | ||
Operating revenues: | ||
Sales of natural gas and NGLs | $ 1,644 | $ 1,119 |
Transportation, processing and other | 157 | 152 |
Trading and marketing gains, net | 31 | 18 |
Operating costs and expenses: | ||
Purchases of natural gas and NGLs | 1,559 | 1,032 |
General and administrative expense | 62 | 62 |
Affiliated Entity | ||
Operating revenues: | ||
Sales of natural gas and NGLs | 289 | 175 |
Operating costs and expenses: | ||
Purchases of natural gas and NGLs | $ 128 | $ 103 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Net income | $ 101 | $ 65 |
Other comprehensive income: | ||
Reclassification of cash flow hedge losses into earnings | 1 | 0 |
Total other comprehensive income | 1 | 0 |
Total comprehensive income | 102 | 65 |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | $ 102 | $ 65 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
OPERATING ACTIVITIES: | ||
Net income | $ 101 | $ 65 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization expense | 94 | 95 |
Earnings from unconsolidated affiliates | (74) | (66) |
Distributions from unconsolidated affiliates | 76 | 87 |
Net unrealized (gains) losses on derivative instruments | (36) | 45 |
Deferred income tax, net | 0 | 1 |
Other, net | 13 | 4 |
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions: | ||
Accounts receivable | 138 | 1 |
Inventories | 8 | 8 |
Accounts payable | (144) | (55) |
Accrued interest | (15) | (15) |
Other current assets and liabilities | (20) | (19) |
Other long-term assets and liabilities | 3 | 0 |
Net cash provided by operating activities | 144 | 151 |
INVESTING ACTIVITIES: | ||
Capital expenditures | (48) | (57) |
Change in restricted cash | 0 | (7) |
Investments in unconsolidated affiliates, net | (20) | (12) |
Net cash used in investing activities | (68) | (76) |
FINANCING ACTIVITIES: | ||
Proceeds from long-term debt | 0 | 892 |
Payments of long-term debt | (195) | (896) |
Net change in advances to predecessor from DCP Midstream, LLC | 418 | 50 |
Distributions to limited partners and general partner | (121) | (121) |
Distributions to noncontrolling interests | (2) | (2) |
Other | (1) | 0 |
Net cash provided by (used in) financing activities | 99 | (77) |
Net change in cash and cash equivalents | 175 | (2) |
Cash and cash equivalents, beginning of period | 1 | 3 |
Cash and cash equivalents, end of period | $ 176 | $ 1 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions | Total | Limited Partners | General Partner | Accumulated Other Comprehensive Loss | Noncontrolling Interests |
Beginning balance (Predecessor) at Dec. 31, 2015 | $ 4,287 | ||||
Beginning balance at Dec. 31, 2015 | 7,092 | $ 2,762 | $ 18 | $ (8) | $ 33 |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Net income | Predecessor | (7) | ||||
Net income | 65 | 41 | 31 | ||
Other comprehensive income | 0 | ||||
Net change in parent advances | Predecessor | 50 | ||||
Net change in parent advances | 50 | ||||
Distributions to limited partners and general partner | (121) | (90) | (31) | ||
Distributions to noncontrolling interests | (2) | (2) | |||
Ending balance (Predecessor) at Mar. 31, 2016 | 4,330 | ||||
Ending balance at Mar. 31, 2016 | 7,084 | 2,713 | 18 | (8) | 31 |
Beginning balance (Predecessor) at Dec. 31, 2016 | 4,220 | ||||
Beginning balance at Dec. 31, 2016 | 6,853 | 2,591 | 18 | (8) | 32 |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Net income | 101 | 59 | 42 | ||
Other comprehensive income | 1 | 1 | |||
Net change in parent advances | 418 | 418 | |||
Acquisition of the DCP Midstream Business | Predecessor | (4,220) | ||||
Acquisition of the DCP Midstream Business | (4,220) | ||||
Deficit purchase price under carrying value of the Transaction | 3,095 | 3,097 | (2) | ||
Issuance of 28,552,480 common units and 2,550,644 general partner units to DCP Midstream, LLC and affiliates | 1,125 | 1,033 | 92 | ||
Distributions to limited partners and general partner | (121) | (90) | (31) | ||
Distributions to noncontrolling interests | (2) | (2) | |||
Ending balance (Predecessor) at Mar. 31, 2017 | 0 | ||||
Ending balance at Mar. 31, 2017 | $ 7,250 | $ 7,108 | $ 121 | $ (9) | $ 30 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Changes in Equity (Parenthetical) | 3 Months Ended |
Mar. 31, 2017shares | |
Issuance of common units (in shares) | 2,550,644 |
Limited Partners | |
Issuance of common units (in shares) | 28,552,480 |
Description of Business and Bas
Description of Business and Basis of Presentation | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business and Basis of Presentation | Description of Business and Basis of Presentation DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or the "Partnership" is a Delaware limited partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information regarding these segments, see Note 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 Enbridge, Inc and its affiliates, or Enbridge. Spectra Energy Corp owned 50% of DCP Midstream, LLC prior to the completion of their merger with Enbridge in the first quarter of 2017. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of March 31, 2017 , DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests. On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a 100% owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. Our predecessor results consist of all of the ownership interests of DCP Midstream, LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our condensed consolidated financial statements include the historical results of The DCP Midstream Business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as an addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. For additional information regarding the Transaction, see Note 3 - Acquisitions. The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2016 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016 . |
New Accounting Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, 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 condensed consolidated statement of cash flows. FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our condensed consolidated financial statements and related disclosures. FASB 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 periods beginning after December 15, 2016. The company has adopted the ASU and it did not have any impact on our condensed consolidated results of operations, cash flows and financial position. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption. |
Acquisitions
Acquisitions | 3 Months Ended |
Mar. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisitions On January 1, 2017 , DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. This represents a transaction between entities under common control and a change in reporting entity. Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, the General Partner, in its capacity as the general partner of the Partnership, entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year. |
Agreements and Transactions wit
Agreements and Transactions with Affiliates | 3 Months Ended |
Mar. 31, 2017 | |
Related Party Transactions [Abstract] | |
Agreements and Transactions with Affiliates | Agreements and Transactions with Affiliates DCP Midstream, LLC Services Agreement and Other General and Administrative Charges Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. Phillips 66 and CPChem We sell a portion of our NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party . Approximately 26% of our NGL production was committed to Phillips 66 and CPChem as of March 31, 2017 . The primary production commitment on certain contracts began a ratable wind down period in December 2014 and expires in January 2019. We ant icipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business. Enbridge and its Affiliates including Spectra Energy Corp We sell a portion of our natural gas and NGLs to Enbridge. In addition, w e purchase natural gas and NGL products from Enbridge. We anticipate continuing to purchase commodities and provide services to Enbridge in the ordinary course of business. Unconsolidated Affiliates We, along with other third party shippers, have entered into 15 -year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15 -year agreements, which commenced at each of the pipelines’ respective in-service dates and expire in 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs. Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million , for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills. We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business. Summary of Transactions with Affiliates The following table summarizes our transactions with affiliates: Three Months Ended March 31, 2017 2016 (Millions) Phillips 66 (including CPChem): Sales of natural gas and NGLs $ 274 $ 171 Purchases of natural gas and NGLs $ 7 $ — Operating and maintenance $ 1 $ — Enbridge (including Spectra Energy Corp): Sales of natural gas and NGLs $ 5 $ — Purchases of natural gas and NGLs $ 8 $ 10 Operating and maintenance $ 1 $ 1 Unconsolidated affiliates: Sales of natural gas and NGLs $ 10 $ 4 Purchases of natural gas and NGLs $ 113 $ 93 Transportation, processing and other $ 1 $ 1 We had balances with affiliates as follows: March 31, December 31, (Millions) Phillips 66 (including CPChem): Accounts receivable $ 85 $ 115 Accounts payable $ 4 $ 4 Other assets $ — $ 2 Enbridge (including Spectra Energy Corp): Accounts receivable $ 5 $ 1 Accounts payable $ 3 $ 3 Other assets $ — $ 1 Other liabilities $ 2 $ 1 Unconsolidated affiliates: Accounts receivable $ 14 $ 18 Accounts payable $ 44 $ 41 Other assets $ 3 $ 5 |
Inventories
Inventories | 3 Months Ended |
Mar. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Inventories | Inventories Inventories were as follows: March 31, December 31, (Millions) Natural gas $ 32 $ 28 NGLs 32 44 Total inventories $ 64 $ 72 We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas and NGLs in the condensed consolidated statements of operations. We recognized no lower of cost or market adjustments during the three months ended March 31, 2017 and $3 million during the three months ended March 31, 2016 . |
Property, Plant and Equipment
Property, Plant and Equipment | 3 Months Ended |
Mar. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, Plant and Equipment A summary of property, plant and equipment by classification is as follows: Depreciable Life March 31, December 31, (Millions) Gathering and transmission systems 20 — 50 Years $ 8,568 $ 8,560 Processing, storage and terminal facilities 35 — 60 Years 5,144 5,134 Other 3 — 30 Years 506 502 Construction work in progress 216 171 Property, plant and equipment 14,434 14,367 Accumulated depreciation (5,387 ) (5,298 ) Property, plant and equipment, net $ 9,047 $ 9,069 Interest capitalized on construction projects was $1 million and less than $1 million for the three months ended March 31, 2017 and 2016 , respectively. Depreciation expense was $92 million and $92 million for the three months ended March 31, 2017 and 2016 , respectively. Asset Retirement Obligations - As of March 31, 2017 and December 31, 2016 , we had asset retirement obligations of $126 million and $124 million , respectively, included in other long-term liabilities in the condensed consolidated balance sheets. Accretion expense was $2 million for the three months ended March 31, 2017 and 2016 , 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 | 3 Months Ended |
Mar. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets | Goodwill and Intangible Assets The carrying amount of goodwill in each of our reporting segments was as follows: Three Months Ended March 31, 2017 (millions) Gathering and Processing Logistics and Marketing Total Balance, beginning of period $ 164 $ 72 $ 236 Balance, end of period $ 164 $ 72 $ 236 We will perform our annual goodwill assessment during the third quarter of 2017 at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. 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 combined balance sheets as intangible assets, net, and are as follows: March 31, December 31, 2017 2016 (millions) Gross carrying amount $ 410 $ 410 Accumulated amortization (153 ) (151 ) Accumulated impairment (122 ) (122 ) Intangible assets, net $ 135 $ 137 For the three months ended March 31, 2017 and 2016, we recorded amortization expense of $2 million and $ 3 million , respectively. As of March 31, 2017 , the remaining amortization periods ranged from approximately 1 years to approximately 18 years, with a weighted-average remaining period of approximately 14 years. Estimated future amortization for these intangible assets is as follows: Estimated Future Amortization (millions) 2017 $ 8 2018 11 2019 11 2020 11 2021 11 Thereafter 83 Total $ 135 |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 3 Months Ended |
Mar. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Investments in Unconsolidated Affiliates The following table summarizes our investments in unconsolidated affiliates: Carrying Value as of Percentage Ownership March 31, December 31, (Millions) DCP Sand Hills Pipeline, LLC 66.67% $ 1,531 $ 1,507 Discovery Producer Services LLC 40.00% 381 385 DCP Southern Hills Pipeline, LLC 66.67% 753 754 Front Range Pipeline LLC 33.33% 166 165 Texas Express Pipeline LLC 10.00% 93 93 Panola Pipeline Company, LLC 15.00% 24 25 Mont Belvieu Enterprise Fractionator 12.50% 22 23 Mont Belvieu 1 Fractionator 20.00% 10 10 Other Various 8 7 Total investments in unconsolidated affiliates $ 2,988 $ 2,969 Earnings from investments in unconsolidated affiliates were as follows: Three Months Ended March 31, 2017 2016 (Millions) DCP Sand Hills Pipeline, LLC $ 31 $ 25 Discovery Producer Services LLC 20 15 DCP Southern Hills Pipeline, LLC 11 12 Front Range Pipeline LLC 4 5 Texas Express Pipeline LLC 2 2 Mont Belvieu Enterprise Fractionator 3 4 Mont Belvieu 1 Fractionator 1 3 Other 2 — Total earnings from unconsolidated affiliates $ 74 $ 66 The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Three Months Ended March 31, 2017 2016 (Millions) Statements of operations: Operating revenue $ 337 $ 307 Operating expenses $ 148 $ 119 Net income $ 188 $ 186 March 31, December 31, (Millions) Balance sheets: Current assets $ 200 $ 232 Long-term assets 5,256 5,274 Current liabilities (134 ) (156 ) Long-term liabilities (202 ) (205 ) Net assets $ 5,120 $ 5,145 |
Fair Value Measurement
Fair Value Measurement | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement | Fair Value Measurement Determination of Fair Value Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market. • Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided. • Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date. • Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant. We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11 - Risk Management and Hedging Activities. Valuation Hierarchy Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows. • Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets. • Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3 — inputs are unobservable and considered significant to the fair value measurement. A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy. Commodity Derivative Assets and Liabilities We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions. Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs. Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data. Interest Rate Derivative Assets and Liabilities We periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between 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 interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation. Nonfinancial Assets and Liabilities We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3. The following table presents the financial instruments carried at fair value as of March 31, 2017 and December 31, 2016 , by condensed consolidated balance sheet caption and by valuation hierarchy, as described above: March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (Millions) Current assets: Commodity derivatives (a) $ 8 $ 15 $ 8 $ 31 $ 5 $ 28 $ 9 $ 42 Short-term investments (b) $ 175 $ — $ — $ 175 $ — $ — $ — $ — Long-term assets: Commodity derivatives (c) $ 1 $ 1 $ 2 $ 4 $ — $ — $ 5 $ 5 Current liabilities: Commodity derivatives (d) $ (7 ) $ (21 ) $ (8 ) $ (36 ) $ (11 ) $ (57 ) $ (23 ) $ (91 ) Long-term liabilities: Commodity derivatives (e) $ — $ (4 ) $ (3 ) $ (7 ) $ (1 ) $ — $ — $ (1 ) (a) Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets. (b) Includes short-term money market securities included in cash and cash equivalents in our condensed consolidated balance sheets. (c) Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets. (d) Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets. (e) Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets. Changes in Levels 1 and 2 Fair Value Measurements The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the three months ended March 31, 2017 and 2016 , there were no transfers into or out of Level 1 and Level 2 of the fair value hierarchy. Changes in Level 3 Fair Value Measurements The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions. We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities. Commodity Derivative Instruments Current Assets Long- Term Assets Current Liabilities Long- Term Liabilities (Millions) Three months ended March 31, 2017 (a): Beginning balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) included in earnings (b) 2 (3 ) 8 (3 ) Settlements (3 ) — 7 — Ending balance $ 8 $ 2 $ (8 ) $ (3 ) Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 2 $ (2 ) $ 8 $ (3 ) Three months ended March 31, 2016 (a): Beginning balance $ 35 $ 4 $ (23 ) $ (6 ) Net unrealized gains (losses) included in earnings (b) 1 (2 ) — 3 Settlements (27 ) — 6 — Ending balance $ 9 $ 2 $ (17 ) $ (3 ) Net unrealized (losses) gains on derivatives still held included in earnings (b) $ — $ (2 ) $ — $ 3 (a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 2017 and 2016 . (b) Represents the amount of total gains or losses for the period, included in trading and marketing gains (losses), 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. March 31, 2017 Product Group Fair Value Forward Curve Range (Millions) Assets NGLs $ 9 $0.25-$1.15 Per gallon Natural gas $ 1 $2.61-$2.87 Per MMBtu Liabilities NGLs $ (8 ) $0.20-$1.15 Per gallon Natural gas $ (3 ) $2.09-$2.72 Per MMBtu Estimated Fair Value of Financial Instruments Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point. We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value. We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our revolving credit facility 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 March 31, 2017 and December 31, 2016 , the carrying value and fair value of our total debt, including current maturities, were as follows: March 31, 2017 December 31, 2016 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (Millions) Total debt $ 5,235 $ 5,307 $ 5,430 $ 5,395 (a) Excludes unamortized issuance costs. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Debt March 31, December 31, (Millions) Senior notes: Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 $ 500 $ 500 Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a) 450 450 Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 325 325 Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a) 600 600 Issued September 2011, interest at 4.750% payable semiannually, due September 2021 500 500 Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 350 350 Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 500 500 Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a) 300 300 Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 300 300 Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 450 450 Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 400 400 Junior subordinated notes: Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 550 550 Credit facility with financial institutions: Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due May 2019 — 195 Fair value adjustments related to interest rate swap fair value hedges (a) 24 24 Unamortized issuance costs (26 ) (23 ) Unamortized discount (14 ) (14 ) Total debt 5,209 5,407 Current maturities of long-term debt 500 500 Total long-term debt $ 4,709 $ 4,907 (a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $24 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt. Credit Facility with Financial Institutions In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019 , or the Credit Agreement, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion . The Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions. The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the maximum Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed: (a) 5.75 to 1.0 for the quarters ending March 31, 2017 through December 31, 2017, (b) 5.50 to 1.0 for the quarter ending March 31, 2018, (c) 5.25 to 1.0 for the quarter ending June 30, 2018, and (d) 5.00 to 1.0 for the quarters thereafter; provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending June 30, 2018 or thereafter, the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of such quarter and at the end of the two fiscal quarters immediately thereafter. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate, plus 0.50% or the LIBOR Market Index rate, plus 1% , plus (b) an applicable margin of 0.45% based on our current credit rating. The Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn and undrawn portions of the approximately $1.4 billion revolving credit facility. As of March 31, 2017 , we had unused borrowing capacity of $1,374 million , net of $24 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by $1,106 million as of March 31, 2017 . Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the May 1, 2019 maturity date. Senior Notes and Junior Subordinated Notes Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on the respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our credit agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our condensed consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes. Debt Maturities (Millions) 2018 $ — 2019 775 2020 600 2021 500 2022 350 Thereafter 2,500 Total $ 4,725 |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 3 Months Ended |
Mar. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management and Hedging Activities | Risk Management and Hedging Activities Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage. Commodity Price Risk Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below. Natural Gas Asset Based Trading and Marketing Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges In order for our natural gas storage facility to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of March 31, 2017 . Commodity Cash Flow Protection Activities We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our hedging programs 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 may use crude oil swaps to mitigate a portion of the commodity price risk exposure for 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. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our condensed consolidated statements of operations as trading and marketing gains, net. NGL Proprietary Trading Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading. Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates. We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt. Credit Risk Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 26% of our NGL production was committed to Phillips 66 and CPChem as of March 31, 2017 . This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to po st cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with o ur credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form. Contingent Credit Features Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances. We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below. • If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions. • Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade. • Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of March 31, 2017 , we were not a party to any agreements that would trigger the cross-default provisions. Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of March 31, 2017 , all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of March 31, 2017 , 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. Collateral As of March 31, 2017 , we had cash deposits of $38 million , included in other current assets in our condensed consolidated balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of March 31, 2017 , we held cash of $5 million , included in other current liabilities in our condensed consolidated balance sheet, related to cash postings by third parties and letters of credit of $31 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements. Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller. Offsetting Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the condensed consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments: March 31, 2017 December 31, 2016 Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount (Millions) Assets: Commodity derivatives $ 35 $ — $ 35 $ 47 $ — $ 47 Liabilities: Commodity derivatives $ (43 ) $ — $ (43 ) $ (92 ) $ — $ (92 ) Summarized Derivative Information The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2017 and December 31, 2016 . Balance Sheet Line Item March 31, December 31, Balance Sheet Line Item March 31, December 31, (Millions) (Millions) Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging Instruments: Commodity derivatives: Commodity derivatives: Unrealized gains on derivative instruments — current $ 31 $ 42 Unrealized losses on derivative instruments — current $ (36 ) $ (91 ) Unrealized gains on derivative instruments — long-term 4 5 Unrealized losses on derivative instruments — long-term (7 ) (1 ) Total $ 35 $ 47 Total $ (43 ) $ (92 ) The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2017 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Losses reclassified from AOCI to earnings — effective portion 1 — — 1 Deficit purchase price under carrying value of the Transaction $ (2 ) $ — $ — $ (2 ) Net deferred (losses) gains in AOCI (ending balance) $ (4 ) $ (6 ) $ 1 $ (9 ) (a) Relates to Discovery, an unconsolidated affiliate. For the three months ended March 31, 2017 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2017 , no derivative losses were reclassified from AOCI to trading and marketing gains, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2016 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. For the three months ended March 31, 2016 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2016 , no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the condensed consolidated statements of operations. The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected: Commodity Derivatives: Statements of Operations Line Item Three Months Ended March 31, 2017 2016 (Millions) Realized (losses) gains $ (5 ) $ 63 Unrealized gains (losses) 36 (45 ) Trading and marketing gains, net $ 31 $ 18 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. March 31, 2017 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net (Short) Long Position (MMBtu) Net (Short) Long Position (Bbls) Net Long Position (MMBtu) 2017 (1,004,000 ) (48,928,700 ) (16,786,124 ) 5,662,500 2018 (416,000 ) 50,000 (156,537 ) 3,192,500 2019 (40,000 ) — (2,203 ) — 2020 (50,000 ) — 240,000 — March 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net (Short) Long Position (MMBtu) 2016 (1,060,000 ) (20,743,700 ) (18,260,483 ) (1,750,000 ) 2017 (292,000 ) (13,717,500 ) (2,467,393 ) 5,670,000 2018 — — 145,500 — |
Partnership Equity and Distribu
Partnership Equity and Distributions | 3 Months Ended |
Mar. 31, 2017 | |
Equity [Abstract] | |
Partnership Equity and Distributions | Partnership Equity and Distributions In January 2017, we issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement as consideration for the Transaction that closed on January 1, 2017. For additional information regarding the Transaction, see Note 3 - Acquisitions. During the three months ended March 31, 2017 and 2016 , we issued no common units pursuant to our 2014 equity distribution agreement. As of March 31, 2017 , approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement. The following table presents our cash distributions paid in 2017 and 2016 : Payment Date Per Unit Distribution Total Cash Distribution (Millions) February 14, 2017 $ 0.78 $ 121 November 14, 2016 $ 0.78 $ 120 August 12, 2016 $ 0.78 $ 121 May 13, 2016 $ 0.78 $ 121 February 12, 2016 $ 0.78 $ 121 |
Equity-Based Compensation
Equity-Based Compensation | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation | Equity-Based Compensation Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the value of common shares or units of Phillips 66, Enbridge and the Partnership. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The DCP Midstream LTIP is administered by the compensation committee of DCP Midstream, LLC's board of directors. All awards are subject to cliff vesting. Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units on the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date. Liability classified share-based compensation cost is remeasured at each reporting date at fair value, based on the closing security price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Equity-based compensation expense was $3 million for the three months ended March 31, 2017 and 2016 , respectively. The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units: Vesting Period (years) Unrecognized Compensation Expense at March 31, 2017 (millions) Estimated Forfeiture Rate Weighted-Average Remaining Vesting (years) DCP Midstream LTIP: Strategic Performance Units (SPUs) 3 5 0%-11% 2 Phantom Units 1-3 4 0%-11% 2 Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our board of directors. The DERs are paid in cash at the end of the performance period. The following tables presents information related to SPUs: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2017 233,311 $ 44.41 $ 45.86 Granted — — — Forfeited — — — Vested — — — Outstanding at March 31, 2017 233,311 $ 44.41 $ 45.86 Expected to vest 219,844 $ 44.35 $ 45.98 The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiture rate and achievement of performance targets. Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2017 207,317 $ 46.80 $ 45.97 Granted — — — Forfeited — — — Vested — — — Outstanding at March 31, 2017 207,317 $ 46.80 $ 45.97 Expected to vest 185,785 $ 46.72 $ 45.90 |
Benefits
Benefits | 3 Months Ended |
Mar. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefits | Benefits We do not have our own employees. The employees supporting our operations are employees of DCP Midstream, LLC, for which we incur charges under the Services Agreement. All DCP Midstream, LLC employees who have reached the age of 18 and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which a range of 4% to 7% of each eligible employee’s qualified earnings is contributed, based on years of service. The 401(k) plan has an automatic enrollment feature, meaning all new employees are enrolled at a 6% contribution level. Employees can opt out of this contribution level or change it at any time. Additionally, DCP Midstream, LLC matches employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During the three months ended March 31, 2017 and 2016 , we expensed plan contributions of $8 million , and $9 million , respectively. DCP Midstream, LLC offers certain eligible executives the opportunity to participate in the Executive Deferred Compensation Plan, or EDC Plan. The EDC Plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. |
Net Income or Loss per Limited
Net Income or Loss per Limited Partner Unit | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income or Loss per Limited Partner Unit | Net Income or Loss per Limited Partner Unit Basic and diluted net income or loss per limited partner unit (or "LPU") is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under the LTIP. The dilutive effect of unit-based awards was 198 and 1,604 equivalent units during the three months ended March 31, 2017 and 2016 respectively. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes We are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for federal income tax purposes. Accordingly, we had no federal income tax expense for the three months ended March 31, 2017 and 2016 , respectively. The State of Texas imposes a margin tax that is assessed at 0.75% of taxable margin apportioned to Texas for the three months ended March 31, 2017 and 2016 , respectively. Income tax expense consists of the following: Three months ended March 31, 2017 2016 (Millions) Current state income tax expense $ 1 $ 1 Deferred federal income tax expense — 1 Total income tax expense $ 1 $ 2 We had net long-term deferred tax liabilities of $28 million as of both March 31, 2017 and December 31, 2016 , included in other long-term liabilities on the condensed consolidated balance sheets. These state deferred tax liabilities relate to our Texas operations and are primarily associated with depreciation related to property, plant and equipment. Our effective tax rate differs from statutory rates, primarily due to being structured as a master limited partnership, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states. |
Commitments and Contingent Liab
Commitments and Contingent Liabilities | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingent Liabilities | Commitments and Contingent Liabilities Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our results of operations, financial position, or cash flow. In January 2016, we reached a settlement with a large producer in the DJ basin and received a cash payment of $89 million , a dedication of a portion of the producer’s production in the DJ Basin under a life of lease agreement and a 15 year dedication of natural gas liquids from the producer and its affiliates to the Sand Hills pipeline in the Delaware basin of the Permian region. The cash consideration was received in February 2016, and we recorded other income, net of $2 million in legal fees, in the condensed consolidated statement of operations for the three months ended March 31, 2016 . Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations. Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus (i) 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 and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows. Operating Leases — We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $ 8 million and $ 9 million during the three months ended March 31, 2017 and 2016 , 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: Minimum Rental Payments (millions) 2017 $ 46 2018 37 2019 34 2020 29 2021 21 Thereafter 42 Total minimum rental payments $ 209 |
Business Segments
Business Segments | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Business Segments | Business Segments Concurrent with the completion of the Transaction in the first quarter of 2017, management reevaluated our reportable segments and determined that our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing. Segment information for prior periods has been retrospectively adjusted to furnish comparative information similar to the pooling method to reflect these reportable segments. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies in our Annual Report on Form 10-K for the year ended December 31, 2016. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering and selling condensate. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminations column. The following tables set forth our segment information: Three Months Ended March 31, 2017 : Gathering and Processing Logistics and Marketing Other Eliminations Total (Millions) Total operating revenue $ 1,359 $ 1,927 $ — $ (1,165 ) $ 2,121 Gross margin (a) $ 376 $ 58 $ — $ — $ 434 Operating and maintenance expense (153 ) (9 ) (5 ) — (167 ) Depreciation and amortization expense (85 ) (4 ) (5 ) — (94 ) General and administrative expense (6 ) (3 ) (53 ) — (62 ) Other expense — (9 ) (1 ) — (10 ) Earnings from unconsolidated affiliates 20 54 — — 74 Interest expense — — (73 ) — (73 ) Income tax expense — — (1 ) — (1 ) Net income (loss) $ 152 $ 87 $ (138 ) $ — $ 101 Net income attributable to noncontrolling interests — — — — — Net income (loss) attributable to partners $ 152 $ 87 $ (138 ) $ — $ 101 Non-cash derivative mark-to-market (b) $ 31 $ 5 $ — $ — $ 36 Non-cash lower of cost or market adjustments $ — $ — $ — $ — $ — Capital expenditures $ 43 $ 1 $ 4 $ — $ 48 Investments in unconsolidated affiliates, net $ — $ 20 $ — $ — $ 20 Three Months Ended March 31, 2016 : Gathering and Processing Logistics and Marketing Other Eliminations Total (Millions) Total operating revenue $ 936 $ 1,264 $ — $ (736 ) $ 1,464 Gross margin (a) $ 269 $ 60 $ — $ — $ 329 Operating and maintenance expense (161 ) (10 ) (8 ) — (179 ) Depreciation and amortization expense (86 ) (4 ) (5 ) — (95 ) General and administrative expense (4 ) (3 ) (55 ) — (62 ) Other income 87 — — — 87 Earnings from unconsolidated affiliates 15 51 — — 66 Interest expense — — (79 ) — (79 ) Income tax expense — — (2 ) — (2 ) Net income (loss) $ 120 $ 94 $ (149 ) $ — $ 65 Net income attributable to noncontrolling interests — — — — — Net income (loss) attributable to partners $ 120 $ 94 $ (149 ) $ — $ 65 Non-cash derivative mark-to-market (b) $ (39 ) $ (6 ) $ — $ — $ (45 ) Non-cash lower of cost or market adjustments $ 3 $ — $ — $ — $ 3 Capital expenditures $ 50 $ 2 $ 5 $ — $ 57 Investments in unconsolidated affiliates, net $ — $ 12 $ — $ — $ 12 March 31, December 31, 2017 2016 (Millions) Segment long-term assets: Gathering and Processing $ 9,035 $ 9,053 Logistics and Marketing 3,288 3,278 Other (c) 276 286 Total long-term assets 12,599 12,617 Current assets 980 994 Total assets $ 13,579 $ 13,611 (a) Gross margin consists of total operating revenues, including trading and marketing gains and losses, less purchases of natural gas and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Three Months Ended March 31, 2017 2016 (Millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 87 $ 91 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable $ 46 $ 13 Other non-cash changes in property, plant and equipment $ — $ (2 ) Issuance of common and general partner units in the Transaction $ 1,125 $ — Deficit purchase price in the Transaction $ 3,097 $ — |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 3 Months Ended |
Mar. 31, 2017 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Information | Condensed Consolidating Financial Information The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. Condensed Consolidating Balance Sheet March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ 175 $ 1 $ — $ 176 Accounts receivable, net — — 651 — 651 Inventories — — 64 — 64 Other — — 89 — 89 Total current assets — 175 805 — 980 Property, plant and equipment, net — — 9,047 — 9,047 Goodwill and intangible assets, net — — 371 — 371 Advances receivable — consolidated subsidiaries 2,832 2,297 — (5,129 ) — Investments in consolidated subsidiaries 4,388 7,182 — (11,570 ) — Investments in unconsolidated affiliates — — 2,988 — 2,988 Other long-term assets — — 193 — 193 Total assets $ 7,220 $ 9,654 $ 13,404 $ (16,699 ) $ 13,579 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 57 $ 833 $ — $ 890 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,129 (5,129 ) — Long-term debt — 4,709 — — 4,709 Other long-term liabilities — — 230 — 230 Total liabilities — 5,266 6,192 (5,129 ) 6,329 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 7,220 4,392 7,187 (11,570 ) 7,229 Accumulated other comprehensive loss — (4 ) (5 ) — (9 ) Total partners’ equity 7,220 4,388 7,182 (11,570 ) 7,220 Noncontrolling interests — — 30 — 30 Total equity 7,220 4,388 7,212 (11,570 ) 7,250 Total liabilities and equity $ 7,220 $ 9,654 $ 13,404 $ (16,699 ) $ 13,579 Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 792 — 792 Inventories — — 72 — 72 Other — — 129 — 129 Total current assets — — 994 — 994 Property, plant and equipment, net — — 9,069 — 9,069 Goodwill and intangible assets, net — — 373 — 373 Advances receivable — consolidated subsidiaries 2,953 2,760 — (5,713 ) — Investments in consolidated subsidiaries 3,868 6,587 — (10,455 ) — Investments in unconsolidated affiliates — — 2,969 — 2,969 Other long-term assets — — 206 — 206 Total assets $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 72 $ 1,051 $ — $ 1,123 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,713 (5,713 ) — Long-term debt — 4,907 — — 4,907 Other long-term liabilities — — 228 — 228 Total liabilities — 5,479 6,992 (5,713 ) 6,758 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 6,821 3,871 6,592 (10,455 ) 6,829 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 6,821 3,868 6,587 (10,455 ) 6,821 Noncontrolling interests — — 32 — 32 Total equity 6,821 3,868 6,619 (10,455 ) 6,853 Total liabilities and equity $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 Condensed Consolidating Statement of Operations Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 1,933 $ — $ 1,933 Transportation, processing and other — — 157 — 157 Trading and marketing gains, net — — 31 — 31 Total operating revenues — — 2,121 — 2,121 Operating costs and expenses: Purchases of natural gas and NGLs — — 1,687 — 1,687 Operating and maintenance expense — — 167 — 167 Depreciation and amortization expense — — 94 — 94 General and administrative expense — — 62 — 62 Other expense — — 10 — 10 Total operating costs and expenses — — 2,020 — 2,020 Operating income — — 101 — 101 Interest expense — (73 ) — — (73 ) Income from consolidated subsidiaries 101 174 — (275 ) — Earnings from unconsolidated affiliates — — 74 — 74 Income before income taxes 101 101 175 (275 ) 102 Income tax expense — — (1 ) — (1 ) Net income 101 101 174 (275 ) 101 Net income attributable to noncontrolling interests — — — — — Net income attributable to partners $ 101 $ 101 $ 174 $ (275 ) $ 101 Condensed Consolidating Statement of Comprehensive Income Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 101 $ 101 $ 174 $ (275 ) $ 101 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 102 102 174 (276 ) 102 Total comprehensive income attributable to noncontrolling interests — — — — — Total comprehensive income attributable to partners $ 102 $ 102 $ 174 $ (276 ) $ 102 Condensed Consolidating Statement of Operations Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 1,294 $ — $ 1,294 Transportation, processing and other — — 152 — 152 Trading and marketing gains, net — — 18 — 18 Total operating revenues — — 1,464 — 1,464 Operating costs and expenses: Purchases of natural gas and NGLs — — 1,135 — 1,135 Operating and maintenance expense — — 179 — 179 Depreciation and amortization expense — — 95 — 95 General and administrative expense — — 62 — 62 Other income — — (87 ) — (87 ) Total operating costs and expenses — — 1,384 — 1,384 Operating income — — 80 — 80 Interest expense, net — (79 ) — — (79 ) Income from consolidated subsidiaries 65 144 — (209 ) — Earnings from unconsolidated affiliates — — 66 — 66 Income before income taxes 65 65 146 (209 ) 67 Income tax expense — — (2 ) — (2 ) Net income 65 65 144 (209 ) 65 Net income attributable to noncontrolling interests — — — — — Net income attributable to partners $ 65 $ 65 $ 144 $ (209 ) $ 65 Condensed Consolidating Statement of Comprehensive Income Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 65 $ 65 $ 144 $ (209 ) $ 65 Total other comprehensive income — — — — — — — — — Total comprehensive income 65 65 144 (209 ) 65 Total comprehensive income attributable to noncontrolling interests — — — — — Total comprehensive income attributable to partners $ 65 $ 65 $ 144 $ (209 ) $ 65 Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (87 ) $ 231 $ — $ 144 INVESTING ACTIVITIES: Intercompany transfers 121 458 — (579 ) — Capital expenditures — — (48 ) — (48 ) Investments in unconsolidated affiliates — — (20 ) — (20 ) Net cash provided by (used in) investing activities 121 458 (68 ) (579 ) (68 ) FINANCING ACTIVITIES: Intercompany transfers — — (579 ) 579 — Payments of long-term debt — (195 ) — — (195 ) Net change in advances to predecessor from DCP Midstream, LLC — — 418 — 418 Distributions to limited partners and general partner (121 ) — — — (121 ) Distributions to noncontrolling interests — — (2 ) — (2 ) Other — (1 ) — — (1 ) Net cash (used in) provided by financing activities (121 ) (196 ) (163 ) 579 99 Net change in cash and cash equivalents — 175 — — 175 Cash and cash equivalents, beginning of period — — 1 — 1 Cash and cash equivalents, end of period $ — $ 175 $ 1 $ — $ 176 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (92 ) $ 243 $ — $ 151 INVESTING ACTIVITIES: Intercompany transfers 121 103 — (224 ) — Capital expenditures — — (57 ) — (57 ) Investments in unconsolidated affiliates — — (12 ) — (12 ) Change in restricted cash — (7 ) — — (7 ) Net cash provided by (used in) investing activities 121 96 (69 ) (224 ) (76 ) FINANCING ACTIVITIES: Intercompany transfers — — (224 ) 224 — Proceeds from long-term debt — 892 — — 892 Payments of long-term debt — (896 ) — — (896 ) Net change in advances to predecessor from DCP Midstream, LLC — — 50 — 50 Distributions to limited partners and general partner (121 ) — — — (121 ) Distributions to noncontrolling interests — — (2 ) — (2 ) Net cash (used in) provided by financing activities (121 ) (4 ) (176 ) 224 (77 ) Net change in cash and cash equivalents — — (2 ) — (2 ) Cash and cash equivalents, beginning of period — — 3 — 3 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events On April 25, 2017 , we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution is payable on May 15, 2017 to unitholders of record on May 9, 2017 . |
Description of Business and B30
Description of Business and Basis of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Consolidation, Subsidiaries or Other Investments, Consolidated Entities | The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. |
Equity Method Investments | Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. |
New Accounting Pronouncements | New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, 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 condensed consolidated statement of cash flows. FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our condensed consolidated financial statements and related disclosures. FASB 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 periods beginning after December 15, 2016. The company has adopted the ASU and it did not have any impact on our condensed consolidated results of operations, cash flows and financial position. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption. |
Fair Value Measurement | Determination of Fair Value Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market. • Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided. • Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date. • Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant. We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11 - Risk Management and Hedging Activities. Valuation Hierarchy Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows. • Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets. • Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3 — inputs are unobservable and considered significant to the fair value measurement. A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy. Commodity Derivative Assets and Liabilities We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions. Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs. Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data. Interest Rate Derivative Assets and Liabilities We periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between 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 interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation. Nonfinancial Assets and Liabilities We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3. |
Derivatives | Commodity Price Risk Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below. Natural Gas Asset Based Trading and Marketing Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges In order for our natural gas storage facility to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of March 31, 2017 . Commodity Cash Flow Protection Activities We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our hedging programs 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 may use crude oil swaps to mitigate a portion of the commodity price risk exposure for 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. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our condensed consolidated statements of operations as trading and marketing gains, net. NGL Proprietary Trading Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading. Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates. We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt. Credit Risk Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 26% of our NGL production was committed to Phillips 66 and CPChem as of March 31, 2017 . This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to po st cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with o ur credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form. Contingent Credit Features Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances. We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below. • If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions. • Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade. • Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of March 31, 2017 , we were not a party to any agreements that would trigger the cross-default provisions. Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of March 31, 2017 , all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of March 31, 2017 , 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. Collateral As of March 31, 2017 , we had cash deposits of $38 million , included in other current assets in our condensed consolidated balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of March 31, 2017 , we held cash of $5 million , included in other current liabilities in our condensed consolidated balance sheet, related to cash postings by third parties and letters of credit of $31 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements. Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller. Offsetting Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the condensed consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. |
Agreements and Transactions w31
Agreements and Transactions with Affiliates (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Related Party Transactions [Abstract] | |
Summary of Transactions with Affiliates | The following table summarizes our transactions with affiliates: Three Months Ended March 31, 2017 2016 (Millions) Phillips 66 (including CPChem): Sales of natural gas and NGLs $ 274 $ 171 Purchases of natural gas and NGLs $ 7 $ — Operating and maintenance $ 1 $ — Enbridge (including Spectra Energy Corp): Sales of natural gas and NGLs $ 5 $ — Purchases of natural gas and NGLs $ 8 $ 10 Operating and maintenance $ 1 $ 1 Unconsolidated affiliates: Sales of natural gas and NGLs $ 10 $ 4 Purchases of natural gas and NGLs $ 113 $ 93 Transportation, processing and other $ 1 $ 1 We had balances with affiliates as follows: March 31, December 31, (Millions) Phillips 66 (including CPChem): Accounts receivable $ 85 $ 115 Accounts payable $ 4 $ 4 Other assets $ — $ 2 Enbridge (including Spectra Energy Corp): Accounts receivable $ 5 $ 1 Accounts payable $ 3 $ 3 Other assets $ — $ 1 Other liabilities $ 2 $ 1 Unconsolidated affiliates: Accounts receivable $ 14 $ 18 Accounts payable $ 44 $ 41 Other assets $ 3 $ 5 |
Inventories (Tables)
Inventories (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventories | Inventories were as follows: March 31, December 31, (Millions) Natural gas $ 32 $ 28 NGLs 32 44 Total inventories $ 64 $ 72 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Classification of Property, Plant and Equipment | A summary of property, plant and equipment by classification is as follows: Depreciable Life March 31, December 31, (Millions) Gathering and transmission systems 20 — 50 Years $ 8,568 $ 8,560 Processing, storage and terminal facilities 35 — 60 Years 5,144 5,134 Other 3 — 30 Years 506 502 Construction work in progress 216 171 Property, plant and equipment 14,434 14,367 Accumulated depreciation (5,387 ) (5,298 ) Property, plant and equipment, net $ 9,047 $ 9,069 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | The carrying amount of goodwill in each of our reporting segments was as follows: Three Months Ended March 31, 2017 (millions) Gathering and Processing Logistics and Marketing Total Balance, beginning of period $ 164 $ 72 $ 236 Balance, end of period $ 164 $ 72 $ 236 |
Schedule of Finite-Lived Intangible Assets | The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying combined balance sheets as intangible assets, net, and are as follows: March 31, December 31, 2017 2016 (millions) Gross carrying amount $ 410 $ 410 Accumulated amortization (153 ) (151 ) Accumulated impairment (122 ) (122 ) Intangible assets, net $ 135 $ 137 |
Schedule of Future Amortization Expense | Estimated future amortization for these intangible assets is as follows: Estimated Future Amortization (millions) 2017 $ 8 2018 11 2019 11 2020 11 2021 11 Thereafter 83 Total $ 135 |
Investments in Unconsolidated35
Investments in Unconsolidated Affiliates (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | The following table summarizes our investments in unconsolidated affiliates: Carrying Value as of Percentage Ownership March 31, December 31, (Millions) DCP Sand Hills Pipeline, LLC 66.67% $ 1,531 $ 1,507 Discovery Producer Services LLC 40.00% 381 385 DCP Southern Hills Pipeline, LLC 66.67% 753 754 Front Range Pipeline LLC 33.33% 166 165 Texas Express Pipeline LLC 10.00% 93 93 Panola Pipeline Company, LLC 15.00% 24 25 Mont Belvieu Enterprise Fractionator 12.50% 22 23 Mont Belvieu 1 Fractionator 20.00% 10 10 Other Various 8 7 Total investments in unconsolidated affiliates $ 2,988 $ 2,969 Earnings from investments in unconsolidated affiliates were as follows: Three Months Ended March 31, 2017 2016 (Millions) DCP Sand Hills Pipeline, LLC $ 31 $ 25 Discovery Producer Services LLC 20 15 DCP Southern Hills Pipeline, LLC 11 12 Front Range Pipeline LLC 4 5 Texas Express Pipeline LLC 2 2 Mont Belvieu Enterprise Fractionator 3 4 Mont Belvieu 1 Fractionator 1 3 Other 2 — Total earnings from unconsolidated affiliates $ 74 $ 66 The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Three Months Ended March 31, 2017 2016 (Millions) Statements of operations: Operating revenue $ 337 $ 307 Operating expenses $ 148 $ 119 Net income $ 188 $ 186 March 31, December 31, (Millions) Balance sheets: Current assets $ 200 $ 232 Long-term assets 5,256 5,274 Current liabilities (134 ) (156 ) Long-term liabilities (202 ) (205 ) Net assets $ 5,120 $ 5,145 |
Fair Value Measurement (Tables)
Fair Value Measurement (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments Carried at Fair Value | The following table presents the financial instruments carried at fair value as of March 31, 2017 and December 31, 2016 , by condensed consolidated balance sheet caption and by valuation hierarchy, as described above: March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (Millions) Current assets: Commodity derivatives (a) $ 8 $ 15 $ 8 $ 31 $ 5 $ 28 $ 9 $ 42 Short-term investments (b) $ 175 $ — $ — $ 175 $ — $ — $ — $ — Long-term assets: Commodity derivatives (c) $ 1 $ 1 $ 2 $ 4 $ — $ — $ 5 $ 5 Current liabilities: Commodity derivatives (d) $ (7 ) $ (21 ) $ (8 ) $ (36 ) $ (11 ) $ (57 ) $ (23 ) $ (91 ) Long-term liabilities: Commodity derivatives (e) $ — $ (4 ) $ (3 ) $ (7 ) $ (1 ) $ — $ — $ (1 ) (a) Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets. (b) Includes short-term money market securities included in cash and cash equivalents in our condensed consolidated balance sheets. (c) Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets. (d) Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets. (e) Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets. |
Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation | Commodity Derivative Instruments Current Assets Long- Term Assets Current Liabilities Long- Term Liabilities (Millions) Three months ended March 31, 2017 (a): Beginning balance $ 9 $ 5 $ (23 ) $ — Net unrealized gains (losses) included in earnings (b) 2 (3 ) 8 (3 ) Settlements (3 ) — 7 — Ending balance $ 8 $ 2 $ (8 ) $ (3 ) Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 2 $ (2 ) $ 8 $ (3 ) Three months ended March 31, 2016 (a): Beginning balance $ 35 $ 4 $ (23 ) $ (6 ) Net unrealized gains (losses) included in earnings (b) 1 (2 ) — 3 Settlements (27 ) — 6 — Ending balance $ 9 $ 2 $ (17 ) $ (3 ) Net unrealized (losses) gains on derivatives still held included in earnings (b) $ — $ (2 ) $ — $ 3 (a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 2017 and 2016 . (b) Represents the amount of total gains or losses for the period, included in trading and marketing gains (losses), net. |
Schedule of Valuation Processes | March 31, 2017 Product Group Fair Value Forward Curve Range (Millions) Assets NGLs $ 9 $0.25-$1.15 Per gallon Natural gas $ 1 $2.61-$2.87 Per MMBtu Liabilities NGLs $ (8 ) $0.20-$1.15 Per gallon Natural gas $ (3 ) $2.09-$2.72 Per MMBtu |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | As of March 31, 2017 and December 31, 2016 , the carrying value and fair value of our total debt, including current maturities, were as follows: March 31, 2017 December 31, 2016 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (Millions) Total debt $ 5,235 $ 5,307 $ 5,430 $ 5,395 (a) Excludes unamortized issuance costs. |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | March 31, December 31, (Millions) Senior notes: Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 $ 500 $ 500 Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a) 450 450 Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 325 325 Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a) 600 600 Issued September 2011, interest at 4.750% payable semiannually, due September 2021 500 500 Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 350 350 Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 500 500 Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a) 300 300 Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 300 300 Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 450 450 Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 400 400 Junior subordinated notes: Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 550 550 Credit facility with financial institutions: Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due May 2019 — 195 Fair value adjustments related to interest rate swap fair value hedges (a) 24 24 Unamortized issuance costs (26 ) (23 ) Unamortized discount (14 ) (14 ) Total debt 5,209 5,407 Current maturities of long-term debt 500 500 Total long-term debt $ 4,709 $ 4,907 (a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $24 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt. |
Future Maturities of Long-Term Debt | Debt Maturities (Millions) 2018 $ — 2019 775 2020 600 2021 500 2022 350 Thereafter 2,500 Total $ 4,725 |
Risk Management and Hedging A38
Risk Management and Hedging Activities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Offsetting Assets | The following summarizes the gross and net amounts of our derivative instruments: March 31, 2017 December 31, 2016 Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount (Millions) Assets: Commodity derivatives $ 35 $ — $ 35 $ 47 $ — $ 47 Liabilities: Commodity derivatives $ (43 ) $ — $ (43 ) $ (92 ) $ — $ (92 ) |
Schedule of Offsetting Liabilities | The following summarizes the gross and net amounts of our derivative instruments: March 31, 2017 December 31, 2016 Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments Net Amount (Millions) Assets: Commodity derivatives $ 35 $ — $ 35 $ 47 $ — $ 47 Liabilities: Commodity derivatives $ (43 ) $ — $ (43 ) $ (92 ) $ — $ (92 ) |
Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value | The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of March 31, 2017 and December 31, 2016 . Balance Sheet Line Item March 31, December 31, Balance Sheet Line Item March 31, December 31, (Millions) (Millions) Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging Instruments: Commodity derivatives: Commodity derivatives: Unrealized gains on derivative instruments — current $ 31 $ 42 Unrealized losses on derivative instruments — current $ (36 ) $ (91 ) Unrealized gains on derivative instruments — long-term 4 5 Unrealized losses on derivative instruments — long-term (7 ) (1 ) Total $ 35 $ 47 Total $ (43 ) $ (92 ) |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) | The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2016 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended March 31, 2017 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Losses reclassified from AOCI to earnings — effective portion 1 — — 1 Deficit purchase price under carrying value of the Transaction $ (2 ) $ — $ — $ (2 ) Net deferred (losses) gains in AOCI (ending balance) $ (4 ) $ (6 ) $ 1 $ (9 ) (a) Relates to Discovery, an unconsolidated affiliate. |
Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments | The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected: Commodity Derivatives: Statements of Operations Line Item Three Months Ended March 31, 2017 2016 (Millions) Realized (losses) gains $ (5 ) $ 63 Unrealized gains (losses) 36 (45 ) Trading and marketing gains, net $ 31 $ 18 |
Schedule of Net Long or Short Positions Expected to be Realized | The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below. March 31, 2017 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net (Short) Long Position (MMBtu) Net (Short) Long Position (Bbls) Net Long Position (MMBtu) 2017 (1,004,000 ) (48,928,700 ) (16,786,124 ) 5,662,500 2018 (416,000 ) 50,000 (156,537 ) 3,192,500 2019 (40,000 ) — (2,203 ) — 2020 (50,000 ) — 240,000 — March 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net (Short) Long Position (Bbls) Net (Short) Long Position (MMBtu) 2016 (1,060,000 ) (20,743,700 ) (18,260,483 ) (1,750,000 ) 2017 (292,000 ) (13,717,500 ) (2,467,393 ) 5,670,000 2018 — — 145,500 — |
Partnership Equity and Distri39
Partnership Equity and Distributions (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Equity [Abstract] | |
Cash Distribution | The following table presents our cash distributions paid in 2017 and 2016 : Payment Date Per Unit Distribution Total Cash Distribution (Millions) February 14, 2017 $ 0.78 $ 121 November 14, 2016 $ 0.78 $ 120 August 12, 2016 $ 0.78 $ 121 May 13, 2016 $ 0.78 $ 121 February 12, 2016 $ 0.78 $ 121 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Fair Value of Unvested Awards | The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units: Vesting Period (years) Unrecognized Compensation Expense at March 31, 2017 (millions) Estimated Forfeiture Rate Weighted-Average Remaining Vesting (years) DCP Midstream LTIP: Strategic Performance Units (SPUs) 3 5 0%-11% 2 Phantom Units 1-3 4 0%-11% 2 |
Schedule of Nonvested Share Activity | The following table presents information related to Phantom Units: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2017 207,317 $ 46.80 $ 45.97 Granted — — — Forfeited — — — Vested — — — Outstanding at March 31, 2017 207,317 $ 46.80 $ 45.97 Expected to vest 185,785 $ 46.72 $ 45.90 The following tables presents information related to SPUs: Units Grant Date Weighted-Average Price Per Unit Measurement Date Weighted-Average Price Per Unit Outstanding at January 1, 2017 233,311 $ 44.41 $ 45.86 Granted — — — Forfeited — — — Vested — — — Outstanding at March 31, 2017 233,311 $ 44.41 $ 45.86 Expected to vest 219,844 $ 44.35 $ 45.98 |
Income Taxes (Tables)
Income Taxes (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Tax Expense | Income tax expense consists of the following: Three months ended March 31, 2017 2016 (Millions) Current state income tax expense $ 1 $ 1 Deferred federal income tax expense — 1 Total income tax expense $ 1 $ 2 |
Commitments and Contingent Li42
Commitments and Contingent Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | Minimum rental payments under our various operating leases in the year indicated are as follows: Minimum Rental Payments (millions) 2017 $ 46 2018 37 2019 34 2020 29 2021 21 Thereafter 42 Total minimum rental payments $ 209 |
Business Segments (Tables)
Business Segments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | The following tables set forth our segment information: Three Months Ended March 31, 2017 : Gathering and Processing Logistics and Marketing Other Eliminations Total (Millions) Total operating revenue $ 1,359 $ 1,927 $ — $ (1,165 ) $ 2,121 Gross margin (a) $ 376 $ 58 $ — $ — $ 434 Operating and maintenance expense (153 ) (9 ) (5 ) — (167 ) Depreciation and amortization expense (85 ) (4 ) (5 ) — (94 ) General and administrative expense (6 ) (3 ) (53 ) — (62 ) Other expense — (9 ) (1 ) — (10 ) Earnings from unconsolidated affiliates 20 54 — — 74 Interest expense — — (73 ) — (73 ) Income tax expense — — (1 ) — (1 ) Net income (loss) $ 152 $ 87 $ (138 ) $ — $ 101 Net income attributable to noncontrolling interests — — — — — Net income (loss) attributable to partners $ 152 $ 87 $ (138 ) $ — $ 101 Non-cash derivative mark-to-market (b) $ 31 $ 5 $ — $ — $ 36 Non-cash lower of cost or market adjustments $ — $ — $ — $ — $ — Capital expenditures $ 43 $ 1 $ 4 $ — $ 48 Investments in unconsolidated affiliates, net $ — $ 20 $ — $ — $ 20 Three Months Ended March 31, 2016 : Gathering and Processing Logistics and Marketing Other Eliminations Total (Millions) Total operating revenue $ 936 $ 1,264 $ — $ (736 ) $ 1,464 Gross margin (a) $ 269 $ 60 $ — $ — $ 329 Operating and maintenance expense (161 ) (10 ) (8 ) — (179 ) Depreciation and amortization expense (86 ) (4 ) (5 ) — (95 ) General and administrative expense (4 ) (3 ) (55 ) — (62 ) Other income 87 — — — 87 Earnings from unconsolidated affiliates 15 51 — — 66 Interest expense — — (79 ) — (79 ) Income tax expense — — (2 ) — (2 ) Net income (loss) $ 120 $ 94 $ (149 ) $ — $ 65 Net income attributable to noncontrolling interests — — — — — Net income (loss) attributable to partners $ 120 $ 94 $ (149 ) $ — $ 65 Non-cash derivative mark-to-market (b) $ (39 ) $ (6 ) $ — $ — $ (45 ) Non-cash lower of cost or market adjustments $ 3 $ — $ — $ — $ 3 Capital expenditures $ 50 $ 2 $ 5 $ — $ 57 Investments in unconsolidated affiliates, net $ — $ 12 $ — $ — $ 12 March 31, December 31, 2017 2016 (Millions) Segment long-term assets: Gathering and Processing $ 9,035 $ 9,053 Logistics and Marketing 3,288 3,278 Other (c) 276 286 Total long-term assets 12,599 12,617 Current assets 980 994 Total assets $ 13,579 $ 13,611 (a) Gross margin consists of total operating revenues, including trading and marketing gains and losses, less purchases of natural gas and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets. |
Supplemental Cash Flow Inform44
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Summary of Supplemental Cash Flow Information | Three Months Ended March 31, 2017 2016 (Millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 87 $ 91 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable $ 46 $ 13 Other non-cash changes in property, plant and equipment $ — $ (2 ) Issuance of common and general partner units in the Transaction $ 1,125 $ — Deficit purchase price in the Transaction $ 3,097 $ — |
Condensed Consolidating Finan45
Condensed Consolidating Financial Information (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Balance Sheets | Condensed Consolidating Balance Sheet March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ 175 $ 1 $ — $ 176 Accounts receivable, net — — 651 — 651 Inventories — — 64 — 64 Other — — 89 — 89 Total current assets — 175 805 — 980 Property, plant and equipment, net — — 9,047 — 9,047 Goodwill and intangible assets, net — — 371 — 371 Advances receivable — consolidated subsidiaries 2,832 2,297 — (5,129 ) — Investments in consolidated subsidiaries 4,388 7,182 — (11,570 ) — Investments in unconsolidated affiliates — — 2,988 — 2,988 Other long-term assets — — 193 — 193 Total assets $ 7,220 $ 9,654 $ 13,404 $ (16,699 ) $ 13,579 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 57 $ 833 $ — $ 890 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,129 (5,129 ) — Long-term debt — 4,709 — — 4,709 Other long-term liabilities — — 230 — 230 Total liabilities — 5,266 6,192 (5,129 ) 6,329 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 7,220 4,392 7,187 (11,570 ) 7,229 Accumulated other comprehensive loss — (4 ) (5 ) — (9 ) Total partners’ equity 7,220 4,388 7,182 (11,570 ) 7,220 Noncontrolling interests — — 30 — 30 Total equity 7,220 4,388 7,212 (11,570 ) 7,250 Total liabilities and equity $ 7,220 $ 9,654 $ 13,404 $ (16,699 ) $ 13,579 Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 792 — 792 Inventories — — 72 — 72 Other — — 129 — 129 Total current assets — — 994 — 994 Property, plant and equipment, net — — 9,069 — 9,069 Goodwill and intangible assets, net — — 373 — 373 Advances receivable — consolidated subsidiaries 2,953 2,760 — (5,713 ) — Investments in consolidated subsidiaries 3,868 6,587 — (10,455 ) — Investments in unconsolidated affiliates — — 2,969 — 2,969 Other long-term assets — — 206 — 206 Total assets $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 72 $ 1,051 $ — $ 1,123 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 5,713 (5,713 ) — Long-term debt — 4,907 — — 4,907 Other long-term liabilities — — 228 — 228 Total liabilities — 5,479 6,992 (5,713 ) 6,758 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 6,821 3,871 6,592 (10,455 ) 6,829 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 6,821 3,868 6,587 (10,455 ) 6,821 Noncontrolling interests — — 32 — 32 Total equity 6,821 3,868 6,619 (10,455 ) 6,853 Total liabilities and equity $ 6,821 $ 9,347 $ 13,611 $ (16,168 ) $ 13,611 |
Condensed Income Statement | Condensed Consolidating Statement of Operations Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 1,933 $ — $ 1,933 Transportation, processing and other — — 157 — 157 Trading and marketing gains, net — — 31 — 31 Total operating revenues — — 2,121 — 2,121 Operating costs and expenses: Purchases of natural gas and NGLs — — 1,687 — 1,687 Operating and maintenance expense — — 167 — 167 Depreciation and amortization expense — — 94 — 94 General and administrative expense — — 62 — 62 Other expense — — 10 — 10 Total operating costs and expenses — — 2,020 — 2,020 Operating income — — 101 — 101 Interest expense — (73 ) — — (73 ) Income from consolidated subsidiaries 101 174 — (275 ) — Earnings from unconsolidated affiliates — — 74 — 74 Income before income taxes 101 101 175 (275 ) 102 Income tax expense — — (1 ) — (1 ) Net income 101 101 174 (275 ) 101 Net income attributable to noncontrolling interests — — — — — Net income attributable to partners $ 101 $ 101 $ 174 $ (275 ) $ 101 Condensed Consolidating Statement of Operations Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, NGLs and condensate $ — $ — $ 1,294 $ — $ 1,294 Transportation, processing and other — — 152 — 152 Trading and marketing gains, net — — 18 — 18 Total operating revenues — — 1,464 — 1,464 Operating costs and expenses: Purchases of natural gas and NGLs — — 1,135 — 1,135 Operating and maintenance expense — — 179 — 179 Depreciation and amortization expense — — 95 — 95 General and administrative expense — — 62 — 62 Other income — — (87 ) — (87 ) Total operating costs and expenses — — 1,384 — 1,384 Operating income — — 80 — 80 Interest expense, net — (79 ) — — (79 ) Income from consolidated subsidiaries 65 144 — (209 ) — Earnings from unconsolidated affiliates — — 66 — 66 Income before income taxes 65 65 146 (209 ) 67 Income tax expense — — (2 ) — (2 ) Net income 65 65 144 (209 ) 65 Net income attributable to noncontrolling interests — — — — — Net income attributable to partners $ 65 $ 65 $ 144 $ (209 ) $ 65 |
Condensed Statement of Comprehensive Income | Condensed Consolidating Statement of Comprehensive Income Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 65 $ 65 $ 144 $ (209 ) $ 65 Total other comprehensive income — — — — — — — — — Total comprehensive income 65 65 144 (209 ) 65 Total comprehensive income attributable to noncontrolling interests — — — — — Total comprehensive income attributable to partners $ 65 $ 65 $ 144 $ (209 ) $ 65 Condensed Consolidating Statement of Comprehensive Income Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 101 $ 101 $ 174 $ (275 ) $ 101 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 102 102 174 (276 ) 102 Total comprehensive income attributable to noncontrolling interests — — — — — Total comprehensive income attributable to partners $ 102 $ 102 $ 174 $ (276 ) $ 102 |
Condensed Consolidating Statements of Cash Flows | Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (87 ) $ 231 $ — $ 144 INVESTING ACTIVITIES: Intercompany transfers 121 458 — (579 ) — Capital expenditures — — (48 ) — (48 ) Investments in unconsolidated affiliates — — (20 ) — (20 ) Net cash provided by (used in) investing activities 121 458 (68 ) (579 ) (68 ) FINANCING ACTIVITIES: Intercompany transfers — — (579 ) 579 — Payments of long-term debt — (195 ) — — (195 ) Net change in advances to predecessor from DCP Midstream, LLC — — 418 — 418 Distributions to limited partners and general partner (121 ) — — — (121 ) Distributions to noncontrolling interests — — (2 ) — (2 ) Other — (1 ) — — (1 ) Net cash (used in) provided by financing activities (121 ) (196 ) (163 ) 579 99 Net change in cash and cash equivalents — 175 — — 175 Cash and cash equivalents, beginning of period — — 1 — 1 Cash and cash equivalents, end of period $ — $ 175 $ 1 $ — $ 176 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (92 ) $ 243 $ — $ 151 INVESTING ACTIVITIES: Intercompany transfers 121 103 — (224 ) — Capital expenditures — — (57 ) — (57 ) Investments in unconsolidated affiliates — — (12 ) — (12 ) Change in restricted cash — (7 ) — — (7 ) Net cash provided by (used in) investing activities 121 96 (69 ) (224 ) (76 ) FINANCING ACTIVITIES: Intercompany transfers — — (224 ) 224 — Proceeds from long-term debt — 892 — — 892 Payments of long-term debt — (896 ) — — (896 ) Net change in advances to predecessor from DCP Midstream, LLC — — 50 — 50 Distributions to limited partners and general partner (121 ) — — — (121 ) Distributions to noncontrolling interests — — (2 ) — (2 ) Net cash (used in) provided by financing activities (121 ) (4 ) (176 ) 224 (77 ) Net change in cash and cash equivalents — — (2 ) — (2 ) Cash and cash equivalents, beginning of period — — 3 — 3 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 |
Description of Business and B46
Description of Business and Basis of Presentation - Additional Information (Detail) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Investments in Greater Than 20% | ||
Business Acquisition [Line Items] | ||
Equity method ownership investment (as percent) | 20.00% | |
Investments in Less Than 20% | ||
Business Acquisition [Line Items] | ||
Equity method ownership investment (as percent) | 20.00% | |
DCP Midstream Operating, LP | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 100.00% | |
DCP Midstream, LLC | DCP Midstream GP, LLC | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 100.00% | |
DCP Midstream, LLC | DCP Midstream LP | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 38.10% | |
Phillips 66 | DCP Midstream, LLC | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 50.00% | |
Enbridge | DCP Midstream, LLC | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 50.00% | |
Spectra Energy | DCP Midstream, LLC | ||
Business Acquisition [Line Items] | ||
Ownership interest percentage by parent | 50.00% |
Acquisitions - Additional Infor
Acquisitions - Additional Information (Detail) - DCP Midstream, LLC $ in Millions | Jan. 01, 2017USD ($)shares |
Business Acquisition [Line Items] | |
Cash acquired | $ 424 |
Debt assumed | 3,150 |
Payment for incentive fee | $ 100 |
Common Units | |
Business Acquisition [Line Items] | |
Equity interest issued, number of units (in shares) | shares | 28,552,480 |
General Partner Units | |
Business Acquisition [Line Items] | |
Equity interest issued, number of units (in shares) | shares | 2,550,644 |
Agreements and Transactions w48
Agreements and Transactions with Affiliates - Additional Information (Detail) - Affiliated Entity $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Related Party Transaction [Line Items] | |
Terms of agreement | 15 years |
Sand Hills | |
Related Party Transaction [Line Items] | |
Terms of agreement | 15 years |
Annual service fee | $ 5 |
Southern Hills | |
Related Party Transaction [Line Items] | |
Terms of agreement | 15 years |
Annual service fee | $ 5 |
Front Range | |
Related Party Transaction [Line Items] | |
Terms of agreement | 15 years |
Texas Express | |
Related Party Transaction [Line Items] | |
Terms of agreement | 15 years |
Phillips 66 | Chevron Phillips Chemical LLC | |
Related Party Transaction [Line Items] | |
Equity method ownership investment (as percent) | 50.00% |
NGLs | |
Related Party Transaction [Line Items] | |
Percent of NGL production committed | 26.00% |
Agreements and Transactions w49
Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Related Party Transaction [Line Items] | ||
Sales of natural gas and NGLs | $ 1,933 | $ 1,294 |
Purchases of natural gas and NGLs | 1,687 | 1,135 |
Operating and maintenance expense | 167 | 179 |
Transportation, processing and other | 157 | 152 |
Affiliated Entity | Phillips 66 | ||
Related Party Transaction [Line Items] | ||
Sales of natural gas and NGLs | 274 | 171 |
Purchases of natural gas and NGLs | 7 | 0 |
Operating and maintenance expense | 1 | 0 |
Affiliated Entity | Enbridge | ||
Related Party Transaction [Line Items] | ||
Sales of natural gas and NGLs | 5 | 0 |
Purchases of natural gas and NGLs | 8 | 10 |
Operating and maintenance expense | 1 | 1 |
Affiliated Entity | Unconsolidated Affiliates | ||
Related Party Transaction [Line Items] | ||
Sales of natural gas and NGLs | 10 | 4 |
Purchases of natural gas and NGLs | 113 | 93 |
Transportation, processing and other | $ 1 | $ 1 |
Agreements and Transactions w50
Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Related Party Transaction [Line Items] | ||
Accounts receivable | $ 104 | $ 134 |
Accounts payable | 51 | 48 |
Phillips 66 | ||
Related Party Transaction [Line Items] | ||
Accounts receivable | 85 | 115 |
Accounts payable | 4 | 4 |
Other assets | 0 | 2 |
Enbridge | ||
Related Party Transaction [Line Items] | ||
Accounts receivable | 5 | 1 |
Accounts payable | 3 | 3 |
Other assets | 0 | 1 |
Other liabilities | 2 | 1 |
Unconsolidated Affiliates | ||
Related Party Transaction [Line Items] | ||
Accounts receivable | 14 | 18 |
Accounts payable | 44 | 41 |
Other assets | $ 3 | $ 5 |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Components Of Inventory [Line Items] | ||
Total inventories | $ 64 | $ 72 |
Natural Gas | ||
Components Of Inventory [Line Items] | ||
Total inventories | 32 | 28 |
NGLs | ||
Components Of Inventory [Line Items] | ||
Total inventories | $ 32 | $ 44 |
Inventories - Additional Inform
Inventories - Additional Information (Detail) - USD ($) | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Inventory Disclosure [Abstract] | ||
Lower of cost or market adjustment | $ 0 | $ 3,000,000 |
Property, Plant and Equipment -
Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 14,434 | $ 14,367 |
Accumulated depreciation | (5,387) | (5,298) |
Property, plant and equipment, net | 9,047 | 9,069 |
Gathering and Transmission Systems | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 8,568 | 8,560 |
Gathering and Transmission Systems | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 20 years | |
Gathering and Transmission Systems | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 50 years | |
Processing, Storage, and Terminal Facilities | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 5,144 | 5,134 |
Processing, Storage, and Terminal Facilities | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 35 years | |
Processing, Storage, and Terminal Facilities | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 60 years | |
Other | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 506 | 502 |
Other | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 3 years | |
Other | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable life of property, plant and equipment | 30 years | |
Construction Work In Progress | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 216 | $ 171 |
Property, Plant and Equipment54
Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Interest capitalized on construction projects | $ 1 | $ 1 | |
Depreciation expense | 92 | 92 | |
Accretion expense | 2 | $ 2 | |
Property and Equipment | |||
Property, Plant and Equipment [Line Items] | |||
Asset retirement obligations | $ 126 | $ 124 |
Goodwill and Intangible Asset55
Goodwill and Intangible Assets - Schedule of Goodwill (Details) $ in Millions | Mar. 31, 2017USD ($) |
Goodwill [Roll Forward] | |
Balance, beginning of period | $ 236 |
Balance, end of period | 236 |
Gathering and Processing | |
Goodwill [Roll Forward] | |
Balance, beginning of period | 164 |
Balance, end of period | 164 |
Logistics and Marketing | |
Goodwill [Roll Forward] | |
Balance, beginning of period | 72 |
Balance, end of period | $ 72 |
Goodwill and Intangible Asset56
Goodwill and Intangible Assets - Schedule of Finite-Lived Intangible Assets (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Gross carrying amount | $ 410 | $ 410 | |
Accumulated amortization | (153) | (151) | |
Accumulated impairment | (122) | (122) | |
Intangible assets, net | 135 | $ 137 | |
Amortization expense | $ 2 | $ 3 |
Goodwill and Intangible Asset57
Goodwill and Intangible Assets - Finite-Lived Intangible Assets, Future Amortization (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Finite-Lived Intangible Assets [Line Items] | ||
2,017 | $ 8 | |
2,018 | 11 | |
2,019 | 11 | |
2,020 | 11 | |
2,021 | 11 | |
Thereafter | 83 | |
Intangible assets, net | $ 135 | $ 137 |
Minimum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Remaining amortization period | 1 year | |
Maximum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Remaining amortization period | 18 years | |
Weighted Average | ||
Finite-Lived Intangible Assets [Line Items] | ||
Remaining amortization period | 14 years |
Investments In Unconsolidated58
Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Schedule of Equity Method Investments [Line Items] | ||
Investments in unconsolidated affiliates | $ 2,988 | $ 2,969 |
DCP Sand Hills Pipeline, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 66.67% | |
Investments in unconsolidated affiliates | $ 1,531 | 1,507 |
Discovery Producer Services LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 40.00% | |
Investments in unconsolidated affiliates | $ 381 | 385 |
DCP Southern Hills Pipeline, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 66.67% | |
Investments in unconsolidated affiliates | $ 753 | 754 |
Front Range Pipeline LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 33.33% | |
Investments in unconsolidated affiliates | $ 166 | 165 |
Texas Express Pipeline LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 10.00% | |
Investments in unconsolidated affiliates | $ 93 | 93 |
Panola Pipeline Company, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 15.00% | |
Investments in unconsolidated affiliates | $ 24 | 25 |
Mont Belvieu Enterprise Fractionator | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 12.50% | |
Investments in unconsolidated affiliates | $ 22 | 23 |
Mont Belvieu 1 Fractionator | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method ownership investment (as percent) | 20.00% | |
Investments in unconsolidated affiliates | $ 10 | 10 |
Other | ||
Schedule of Equity Method Investments [Line Items] | ||
Investments in unconsolidated affiliates | $ 8 | $ 7 |
Investments in Unconsolidated59
Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | $ 74 | $ 66 |
DCP Sand Hills Pipeline, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 31 | 25 |
Discovery Producer Services LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 20 | 15 |
DCP Southern Hills Pipeline, LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 11 | 12 |
Front Range Pipeline LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 4 | 5 |
Texas Express Pipeline LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 2 | 2 |
Mont Belvieu Enterprise Fractionator | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 3 | 4 |
Mont Belvieu 1 Fractionator | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | 1 | 3 |
Other | ||
Schedule of Equity Method Investments [Line Items] | ||
Earnings from unconsolidated affiliates | $ 2 | $ 0 |
Investments in Unconsolidated60
Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | ||
Operating revenue | $ 337 | $ 307 |
Operating expenses | 148 | 119 |
Net income | $ 188 | $ 186 |
Investments in Unconsolidated61
Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Equity Method Investments and Joint Ventures [Abstract] | ||
Current assets | $ 200 | $ 232 |
Long-term assets | 5,256 | 5,274 |
Current liabilities | (134) | (156) |
Long-term liabilities | (202) | (205) |
Net assets | $ 5,120 | $ 5,145 |
Fair Value Measurement - Financ
Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Short-term investments | $ 175 | $ 0 |
Current Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 31 | 42 |
Long- Term Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 4 | 5 |
Current Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (36) | (91) |
Long- Term Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (7) | (1) |
Level 1 | Current Assets | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Short-term investments | 175 | 0 |
Level 1 | Current Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 8 | 5 |
Level 1 | Long- Term Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 1 | 0 |
Level 1 | Current Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (7) | (11) |
Level 1 | Long- Term Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 0 | (1) |
Level 2 | Current Assets | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Short-term investments | 0 | 0 |
Level 2 | Current Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 15 | 28 |
Level 2 | Long- Term Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 1 | 0 |
Level 2 | Current Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (21) | (57) |
Level 2 | Long- Term Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (4) | 0 |
Level 3 | Current Assets | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Short-term investments | 0 | 0 |
Level 3 | Current Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 8 | 9 |
Level 3 | Long- Term Assets | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | 2 | 5 |
Level 3 | Current Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | (8) | (23) |
Level 3 | Long- Term Liabilities | Commodity derivatives | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Commodity derivatives | $ (3) | $ 0 |
Fair Value Measurement - Conden
Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Current Assets | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning balance | $ 9 | $ 35 |
Net realized and unrealized gains (losses) included in earnings | 2 | 1 |
Settlements | (3) | (27) |
Ending balance | 8 | 9 |
Net unrealized gains (losses) on derivatives still held included in earnings | 2 | 0 |
Long- Term Assets | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning balance | 5 | 4 |
Net realized and unrealized gains (losses) included in earnings | (3) | (2) |
Settlements | 0 | 0 |
Ending balance | 2 | 2 |
Net unrealized gains (losses) on derivatives still held included in earnings | (2) | (2) |
Current Liabilities | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning balance | (23) | (23) |
Net realized and unrealized (losses) gains included in earnings | 8 | 0 |
Settlements | 7 | 6 |
Ending balance | (8) | (17) |
Net unrealized gains (losses) on derivatives still held included in earnings | 8 | 0 |
Long- Term Liabilities | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Beginning balance | 0 | (6) |
Net realized and unrealized (losses) gains included in earnings | (3) | 3 |
Settlements | 0 | 0 |
Ending balance | (3) | (3) |
Net unrealized gains (losses) on derivatives still held included in earnings | $ (3) | $ 3 |
Fair Value Measurement - Schedu
Fair Value Measurement - Schedule of Valuation Processes (Detail) - Level 3 - Market Approach Valuation Technique $ in Millions | Mar. 31, 2017USD ($)$ / MMBTU$ / gal |
Derivative Liabilities | NGLs | Maximum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Liabilities, fair value | $ | $ (8) |
Forward Curve Range | $ / gal | 1.15 |
Derivative Liabilities | NGLs | Minimum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / gal | 0.20 |
Derivative Liabilities | Natural Gas | Maximum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Liabilities, fair value | $ | $ (3) |
Forward Curve Range | $ / MMBTU | 2.72 |
Derivative Liabilities | Natural Gas | Minimum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / MMBTU | 2.09 |
Derivative Assets | NGLs | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Assets, fair value | $ | $ 9 |
Derivative Assets | NGLs | Maximum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / gal | 1.15 |
Derivative Assets | NGLs | Minimum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / gal | 0.25 |
Derivative Assets | Natural Gas | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Assets, fair value | $ | $ 1 |
Derivative Assets | Natural Gas | Maximum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / MMBTU | 2.87 |
Derivative Assets | Natural Gas | Minimum | |
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items] | |
Forward Curve Range | $ / MMBTU | 2.61 |
Fair Value Measurement - Carryi
Fair Value Measurement - Carrying Value and Fair Value of Debt (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Fair Value Disclosures [Abstract] | ||
Total Debt, Carrying Value | $ 5,235 | $ 5,430 |
Total Debt, Fair Value | $ 5,307 | $ 5,395 |
Debt - Schedule of Long-Term De
Debt - Schedule of Long-Term Debt (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Line of Credit Facility [Line Items] | ||
Fair value adjustments related to interest rate swap fair value hedges | $ 24 | $ 24 |
Unamortized issuance costs | (26) | (23) |
Unamortized discount | (14) | (14) |
Total debt | 5,209 | 5,407 |
Current maturities of long-term debt | 500 | 500 |
Long-term debt | 4,709 | 4,907 |
Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Revolving Credit Facility Issued Amount | 0 | $ 195 |
Weighted-average variable interest rate | 2.01% | |
Senior notes | Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 500 | $ 500 |
Debt interest rate percentage | 2.50% | |
Senior notes | Issued February 2009, interest at 9.750% payable semiannually, due March 2019 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 450 | 450 |
Debt interest rate percentage | 9.75% | |
Senior notes | Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 325 | 325 |
Debt interest rate percentage | 2.70% | |
Senior notes | Issued March 2010, interest at 5.350% payable semiannually, due March 2020 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 600 | 600 |
Debt interest rate percentage | 5.35% | |
Senior notes | Issued September 2011, interest at 4.750% payable semiannually, due September 2021 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 500 | 500 |
Debt interest rate percentage | 4.75% | |
Senior notes | Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 350 | 350 |
Debt interest rate percentage | 4.95% | |
Senior notes | Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 500 | 500 |
Debt interest rate percentage | 3.875% | |
Senior notes | Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 300 | 300 |
Debt interest rate percentage | 8.125% | |
Senior notes | Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 300 | 300 |
Debt interest rate percentage | 6.45% | |
Senior notes | Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 450 | 450 |
Debt interest rate percentage | 6.75% | |
Senior notes | Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 400 | 400 |
Debt interest rate percentage | 5.60% | |
Junior subordinated notes | Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 | ||
Line of Credit Facility [Line Items] | ||
Debt Securities Issued Amount | $ 550 | $ 550 |
Debt interest rate percentage | 5.85% |
Debt - Additional Information (
Debt - Additional Information (Detail) | 3 Months Ended | ||
Mar. 31, 2017USD ($) | Feb. 28, 2017USD ($) | Jan. 31, 2017USD ($) | |
Debt Instrument [Line Items] | |||
Letter of credit amount outstanding | $ 13,000,000 | ||
Interest deferment period | 5 years | ||
Credit Agreement | |||
Debt Instrument [Line Items] | |||
Line of credit maximum borrowing capacity | $ 1,400,000,000 | $ 1,400,000,000 | $ 1,250,000,000 |
Basis spread determined by credit rating | 0.45% | ||
Commitment fee percentage | 0.30% | ||
Unused capacity under the credit agreement | $ 1,374,000,000 | ||
Letter of credit amount outstanding | 24,000,000 | ||
Debt covenants, maximum borrowing amount | $ 1,106,000,000 | ||
Credit Agreement | LIBOR | |||
Debt Instrument [Line Items] | |||
Variable rate basis spread | 1.45% | ||
Credit Agreement | Federal Funds Rate | |||
Debt Instrument [Line Items] | |||
Variable rate basis spread | 0.50% | ||
Credit Agreement | LIBOR Market Index | |||
Debt Instrument [Line Items] | |||
Variable rate basis spread | 1.00% | ||
Credit Agreement | Maximum | |||
Debt Instrument [Line Items] | |||
Maximum leverage ratio in event of acquisition | 5.50 | ||
Credit Agreement | Quarters Ending March 31, 2017 through December 31, 2017 | Maximum | |||
Debt Instrument [Line Items] | |||
Maximum leverage ratio | 5.75 | ||
Credit Agreement | Quarter Ending March 31, 2018 | Maximum | |||
Debt Instrument [Line Items] | |||
Maximum leverage ratio | 5.50 | ||
Credit Agreement | Quarter Ending June 30, 2018 | Maximum | |||
Debt Instrument [Line Items] | |||
Maximum leverage ratio | 5.25 | ||
Credit Agreement | Quarters After June 30, 2018 | Maximum | |||
Debt Instrument [Line Items] | |||
Maximum leverage ratio | 5 |
Debt - Future Maturities of Lon
Debt - Future Maturities of Long-Term Debt (Detail) $ in Millions | Mar. 31, 2017USD ($) |
Maturities of Long-term Debt [Abstract] | |
2,018 | $ 0 |
2,019 | 775 |
2,020 | 600 |
2,021 | 500 |
2,022 | 350 |
Thereafter | 2,500 |
Total principal | $ 4,725 |
Risk Management and Hedging A69
Risk Management and Hedging Activities - Additional Information (Detail) - USD ($) | 3 Months Ended | |||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | ||||
AOCI, cash flow hedge | $ (7,250,000,000) | $ (7,084,000,000) | $ (6,853,000,000) | $ (7,092,000,000) |
Collateral, cash deposits | 38,000,000 | |||
Letter of credit amount outstanding | 13,000,000 | |||
Collateral, cash held | 5,000,000 | |||
Letters of credit received | 31,000,000 | |||
Gain (loss) on hedge ineffectiveness | 0 | 0 | ||
Gain (loss) on discontinuation of cash flow hedge | $ 0 | 0 | ||
Affiliated Entity | NGLs | ||||
Derivative [Line Items] | ||||
Percent of NGL production committed | 26.00% | |||
Accumulated Net Gain (Loss) from Cash Flow Hedges | ||||
Derivative [Line Items] | ||||
AOCI, cash flow hedge | $ 9,000,000 | 8,000,000 | 8,000,000 | 8,000,000 |
Accumulated Net Gain (Loss) from Cash Flow Hedges | Commodity derivatives | ||||
Derivative [Line Items] | ||||
AOCI, cash flow hedge | $ 6,000,000 | $ 6,000,000 | $ 6,000,000 | $ 6,000,000 |
Risk Management and Hedging A70
Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity derivatives - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Offsetting Assets [Line Items] | |||
Gross Amounts of Assets Presented in the Balance Sheet | $ 35 | $ 47 | |
Amounts Not Offset in the Balance Sheet - Financial Instruments | 0 | 0 | |
Net Amount | 35 | $ 47 | |
Offsetting Liabilities [Line Items] | |||
Gross Amounts of Liabilities Presented in the Balance Sheet | $ (43) | (92) | |
Amounts Not Offset in the Balance Sheet - Financial Instruments | 0 | 0 | |
Net Amount | $ (43) | $ (92) |
Risk Management and Hedging A71
Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative Asset [Abstract] | ||
Unrealized gains on derivative instruments — current | $ 31 | $ 42 |
Unrealized gains on derivative instruments — long-term | 4 | 5 |
Derivative Liability [Abstract] | ||
Unrealized losses on derivative instruments — long-term | (7) | (1) |
Commodity derivatives | Derivative Asset Not Designated As Hedging Instruments | ||
Derivative Asset [Abstract] | ||
Unrealized gains on derivative instruments — current | 31 | 42 |
Unrealized gains on derivative instruments — long-term | 4 | 5 |
Total | 35 | 47 |
Commodity derivatives | Derivative Liabilities Not Designated As Hedging Instruments | ||
Derivative Liability [Abstract] | ||
Unrealized losses on derivative instruments — current | (36) | (91) |
Unrealized losses on derivative instruments — long-term | (7) | (1) |
Total | $ (43) | $ (92) |
Risk Management and Hedging A72
Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |
Beginning balance | $ 6,853 |
Ending balance | 7,250 |
Accumulated Net Gain (Loss) from Cash Flow Hedges | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |
Beginning balance | (8) |
Losses reclassified from AOCI to earnings — effective portion | 1 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (2) |
Ending balance | (9) |
Accumulated Net Gain (Loss) from Cash Flow Hedges | Interest Rate Derivatives | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |
Beginning balance | (3) |
Losses reclassified from AOCI to earnings — effective portion | 1 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (2) |
Ending balance | (4) |
Accumulated Net Gain (Loss) from Cash Flow Hedges | Commodity derivatives | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |
Beginning balance | (6) |
Losses reclassified from AOCI to earnings — effective portion | 0 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 |
Ending balance | (6) |
Accumulated Net Gain (Loss) from Cash Flow Hedges | Foreign Currency Derivatives | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |
Beginning balance | 1 |
Losses reclassified from AOCI to earnings — effective portion | 0 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 |
Ending balance | $ 1 |
Risk Management and Hedging A73
Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Derivative [Line Items] | ||
Trading and marketing gains, net | $ 31 | $ 18 |
Derivative Assets Not Designated As Hedging Instruments | Third Party | Commodity derivatives | ||
Derivative [Line Items] | ||
Realized (losses) gains | (5) | 63 |
Unrealized gains (losses) | 36 | (45) |
Trading and marketing gains, net | $ 31 | $ 18 |
Risk Management and Hedging A74
Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail) | 3 Months Ended | |
Mar. 31, 2017MMBTUbbl | Mar. 31, 2016MMBTUbbl | |
Crude Oil | ||
Net (Short) Position, Volume [Abstract] | ||
Net (Short) Position (Bbls), Year One | bbl | (1,004,000) | (1,060,000) |
Net (Short) Position (Bbls), Year Two | bbl | (416,000) | (292,000) |
Net (Short) Position (Bbls), Year Three | bbl | (40,000) | 0 |
Net (Short) Position (Bbls), Year Four | bbl | (50,000) | |
Natural Gas | ||
Net Long (Short) Position, MMBtu [Abstract] | ||
Net Long (Short) Position (MMBtu), Year One | MMBTU | (48,928,700) | (20,743,700) |
Net Long (Short) Position (MMBtu), Year Two | MMBTU | 50,000 | (13,717,500) |
Net Long (Short) Position (MMBtu), Year Three | MMBTU | 0 | 0 |
Net Long (Short) Position (MMBtu), Year Four | MMBTU | 0 | |
NGLs | ||
Net (Short) Position, Volume [Abstract] | ||
Net (Short) Position (Bbls), Year One | bbl | (16,786,124) | (18,260,483) |
Net (Short) Position (Bbls), Year Two | bbl | (156,537) | (2,467,393) |
Net (Short) Position (Bbls), Year Three | bbl | (2,203) | 145,500 |
Net (Short) Position (Bbls), Year Four | bbl | 240,000 | |
Natural Gas Basis Swaps | ||
Net Long (Short) Position, MMBtu [Abstract] | ||
Net Long (Short) Position (MMBtu), Year One | MMBTU | 5,662,500 | (1,750,000) |
Net Long (Short) Position (MMBtu), Year Two | MMBTU | 3,192,500 | 5,670,000 |
Net Long (Short) Position (MMBtu), Year Three | MMBTU | 0 | 0 |
Net Long (Short) Position (MMBtu), Year Four | MMBTU | 0 |
Partnership Equity and Distri75
Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ in Millions | Jan. 01, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 |
Partnership Equity And Distribution [Line Items] | ||||
Common unitholders, units issued (in shares) | 143,302,328 | 114,749,848 | ||
2014 Equity Distribution Agreement | ||||
Partnership Equity And Distribution [Line Items] | ||||
Common unitholders, units issued (in shares) | 0 | 0 | ||
Offer value of common stock unit remaining available for sale | $ 349 | |||
DCP Midstream, LLC | Common Units | ||||
Partnership Equity And Distribution [Line Items] | ||||
Equity interest issued, number of units (in shares) | 28,552,480 | |||
DCP Midstream, LLC | General Partner Units | ||||
Partnership Equity And Distribution [Line Items] | ||||
Equity interest issued, number of units (in shares) | 2,550,644 |
Partnership Equity and Distri76
Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Partnership Equity And Distribution [Line Items] | ||
Total Cash Distribution (Millions) | $ 121 | $ 121 |
February 14, 2017 | ||
Partnership Equity And Distribution [Line Items] | ||
Per Unit Distribution (in dollars per share) | $ 0.78 | |
Total Cash Distribution (Millions) | $ 121 | |
November 14, 2016 | ||
Partnership Equity And Distribution [Line Items] | ||
Per Unit Distribution (in dollars per share) | $ 0.78 | |
Total Cash Distribution (Millions) | $ 120 | |
August 12, 2016 | ||
Partnership Equity And Distribution [Line Items] | ||
Per Unit Distribution (in dollars per share) | $ 0.78 | |
Total Cash Distribution (Millions) | $ 121 | |
May 13, 2016 | ||
Partnership Equity And Distribution [Line Items] | ||
Per Unit Distribution (in dollars per share) | $ 0.78 | |
Total Cash Distribution (Millions) | $ 121 | |
February 12, 2016 | ||
Partnership Equity And Distribution [Line Items] | ||
Per Unit Distribution (in dollars per share) | $ 0.78 | |
Total Cash Distribution (Millions) | $ 121 |
Equity-Based Compensation - Sha
Equity-Based Compensation - Share-Based Compensation Expense (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Share-based compensation expense | $ 3 | $ 3 |
Equity-Based Compensation - Fai
Equity-Based Compensation - Fair Value of Awards (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Strategic Performance Units (SPUs) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting Period (years) | 3 years |
Unrecognized Compensation Expense at March 31, 2017 (millions) | $ 5 |
Weighted-Average Remaining Vesting (years) | 2 years |
Strategic Performance Units (SPUs) | Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Estimated Forfeiture Rate | 0.00% |
Strategic Performance Units (SPUs) | Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Estimated Forfeiture Rate | 11.00% |
Phantom Units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Expense at March 31, 2017 (millions) | $ 4 |
Weighted-Average Remaining Vesting (years) | 2 years |
Phantom Units | Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting Period (years) | 1 year |
Estimated Forfeiture Rate | 0.00% |
Phantom Units | Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting Period (years) | 3 years |
Estimated Forfeiture Rate | 11.00% |
Equity-Based Compensation - Per
Equity-Based Compensation - Performance Units and Phantom Units (Details) - $ / shares | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | |
Strategic Performance Units (SPUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum vesting percentage | 200.00% | ||
Vesting Period (years) | 3 years | ||
Units (in shares): | |||
Beginning balance (in shares) | 233,311 | ||
Granted (in shares) | 0 | ||
Forfeited (in shares) | 0 | ||
Vested (in shares) | 0 | ||
Ending balance (in shares) | 233,311 | ||
Expected to vest (in shares) | 219,844 | ||
Grant Date Weighted-Average Price Per Unit (in dollars per share): | |||
Beginning of Period, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 44.41 | ||
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Forfeited, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
End of Period, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | 44.41 | ||
Expected to vest, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 44.35 | ||
Measurement Date Weighted-Average Price Per Unit (in dollars per share): | |||
Beginning Balance, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | 45.86 | 45.86 | $ 45.86 |
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Forfeited, Measurement Date Weighted-Average Price Per Unit, (in dollars per share) | 0 | ||
Ending Balance, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 45.86 | ||
Expected to vest, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 45.98 | ||
Phantom Units | |||
Units (in shares): | |||
Beginning balance (in shares) | 207,317 | ||
Granted (in shares) | 0 | ||
Forfeited (in shares) | 0 | ||
Vested (in shares) | 0 | ||
Ending balance (in shares) | 207,317 | ||
Expected to vest (in shares) | 185,785 | ||
Grant Date Weighted-Average Price Per Unit (in dollars per share): | |||
Beginning of Period, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 46.80 | ||
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Forfeited, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
End of Period, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | 46.80 | ||
Expected to vest, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 46.72 | ||
Measurement Date Weighted-Average Price Per Unit (in dollars per share): | |||
Beginning Balance, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | 45.97 | 45.97 | $ 45.97 |
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share) | 0 | ||
Forfeited, Measurement Date Weighted-Average Price Per Unit, (in dollars per share) | 0 | ||
Ending Balance, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 45.97 | ||
Expected to vest, Grant Date Weighted-Average Price Per Unit, (in dollars per share) | $ 45.90 |
Benefits (Details)
Benefits (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Defined Contribution Plan Disclosure [Line Items] | ||
Eligibility minimum age | 18 years | |
Eligibility hours per week | 20 hours | |
Automatic enrollment percentage | 6.00% | |
Employer matching contribution percent of employees' gross pay | 6.00% | |
Defined contribution cost | $ 8 | $ 9 |
Minimum | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Employer discretionary contribution percentage | 4.00% | |
Maximum | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Employer discretionary contribution percentage | 7.00% |
Net Income or Loss per Limite81
Net Income or Loss per Limited Partner Unit - Additional Information (Detail) - shares | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Earnings Per Share [Abstract] | ||
Dilutive effect of unit-based awards (in shares) | 198 | 1,604 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Federal income tax expense (benefit) | $ 0 | $ 0 | |
State gross margin tax rate (as percent) | 0.75% | 0.75% | |
Current state income tax expense | $ 1,000,000 | $ 1,000,000 | |
Deferred federal income tax expense | 0 | 1,000,000 | |
Income tax expense | 1,000,000 | $ 2,000,000 | |
Deferred income taxes | $ 28,000,000 | $ 28,000,000 |
Commitments and Contingent Li83
Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | |
Jan. 31, 2016 | Mar. 31, 2017 | Mar. 31, 2016 | |
Loss Contingencies [Line Items] | |||
Rent expense | $ 8 | $ 9 | |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2,017 | 46 | ||
2,018 | 37 | ||
2,019 | 34 | ||
2,020 | 29 | ||
2,021 | 21 | ||
Thereafter | 42 | ||
Total minimum rental payments | $ 209 | ||
Large Producer in DJ Basin | |||
Loss Contingencies [Line Items] | |||
Proceeds from legal settlements | $ 89 | ||
Litigation settlement lease agreement term | 15 years | ||
Gain on legal settlement | $ 2 |
Business Segments - Segment Inf
Business Segments - Segment Information (Detail) | 3 Months Ended | |
Mar. 31, 2017USD ($)Segment | Mar. 31, 2016USD ($) | |
Segment Reporting [Abstract] | ||
Number of reportable segments | Segment | 2 | |
Segment Reporting Information [Line Items] | ||
Total operating revenues | $ 2,121,000,000 | $ 1,464,000,000 |
Gross margin | 434,000,000 | 329,000,000 |
Operating and maintenance expense | (167,000,000) | (179,000,000) |
Depreciation and amortization expense | (94,000,000) | (95,000,000) |
General and administrative expense | (62,000,000) | (62,000,000) |
Other expense (income), net | (10,000,000) | 87,000,000 |
Earnings from unconsolidated affiliates | 74,000,000 | 66,000,000 |
Interest expense, net | (73,000,000) | (79,000,000) |
Income tax expense | (1,000,000) | (2,000,000) |
Net income | 101,000,000 | 65,000,000 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 101,000,000 | 65,000,000 |
Non-cash derivative mark-to-market | 36,000,000 | (45,000,000) |
Non-cash lower of cost or market adjustments | 0 | 3,000,000 |
Capital expenditures | 48,000,000 | 57,000,000 |
Investments in unconsolidated affiliates, net | 20,000,000 | 12,000,000 |
Operating Segments | Gathering and Processing | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | 1,359,000,000 | 936,000,000 |
Gross margin | 376,000,000 | 269,000,000 |
Operating and maintenance expense | (153,000,000) | (161,000,000) |
Depreciation and amortization expense | (85,000,000) | (86,000,000) |
General and administrative expense | (6,000,000) | (4,000,000) |
Other expense (income), net | 0 | 87,000,000 |
Earnings from unconsolidated affiliates | 20,000,000 | 15,000,000 |
Interest expense, net | 0 | 0 |
Income tax expense | 0 | 0 |
Net income | 152,000,000 | 120,000,000 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 152,000,000 | 120,000,000 |
Non-cash derivative mark-to-market | 31,000,000 | (39,000,000) |
Non-cash lower of cost or market adjustments | 0 | 3,000,000 |
Capital expenditures | 43,000,000 | 50,000,000 |
Investments in unconsolidated affiliates, net | 0 | 0 |
Operating Segments | Logistics and Marketing | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | 1,927,000,000 | 1,264,000,000 |
Gross margin | 58,000,000 | 60,000,000 |
Operating and maintenance expense | (9,000,000) | (10,000,000) |
Depreciation and amortization expense | (4,000,000) | (4,000,000) |
General and administrative expense | (3,000,000) | (3,000,000) |
Other expense (income), net | (9,000,000) | 0 |
Earnings from unconsolidated affiliates | 54,000,000 | 51,000,000 |
Interest expense, net | 0 | 0 |
Income tax expense | 0 | 0 |
Net income | 87,000,000 | 94,000,000 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 87,000,000 | 94,000,000 |
Non-cash derivative mark-to-market | 5,000,000 | (6,000,000) |
Non-cash lower of cost or market adjustments | 0 | 0 |
Capital expenditures | 1,000,000 | 2,000,000 |
Investments in unconsolidated affiliates, net | 20,000,000 | 12,000,000 |
Other | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | 0 | 0 |
Gross margin | 0 | 0 |
Operating and maintenance expense | (5,000,000) | (8,000,000) |
Depreciation and amortization expense | (5,000,000) | (5,000,000) |
General and administrative expense | (53,000,000) | (55,000,000) |
Other expense (income), net | (1,000,000) | 0 |
Earnings from unconsolidated affiliates | 0 | 0 |
Interest expense, net | (73,000,000) | (79,000,000) |
Income tax expense | (1,000,000) | (2,000,000) |
Net income | (138,000,000) | (149,000,000) |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | (138,000,000) | (149,000,000) |
Non-cash derivative mark-to-market | 0 | 0 |
Non-cash lower of cost or market adjustments | 0 | 0 |
Capital expenditures | 4,000,000 | 5,000,000 |
Investments in unconsolidated affiliates, net | 0 | 0 |
Eliminations | ||
Segment Reporting Information [Line Items] | ||
Total operating revenues | (1,165,000,000) | (736,000,000) |
Gross margin | 0 | 0 |
Operating and maintenance expense | 0 | 0 |
Depreciation and amortization expense | 0 | 0 |
General and administrative expense | 0 | 0 |
Other expense (income), net | 0 | 0 |
Earnings from unconsolidated affiliates | 0 | 0 |
Interest expense, net | 0 | 0 |
Income tax expense | 0 | 0 |
Net income | 0 | 0 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 0 | 0 |
Non-cash derivative mark-to-market | 0 | 0 |
Non-cash lower of cost or market adjustments | 0 | 0 |
Capital expenditures | 0 | 0 |
Investments in unconsolidated affiliates, net | $ 0 | $ 0 |
Business Segments - Segment Ass
Business Segments - Segment Assets (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Segment long-term assets | $ 12,599 | $ 12,617 |
Current assets | 980 | 994 |
Total assets | 13,579 | 13,611 |
Operating Segments | Gathering and Processing | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Segment long-term assets | 9,035 | 9,053 |
Operating Segments | Logistics and Marketing | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Segment long-term assets | 3,288 | 3,278 |
Other | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Segment long-term assets | $ 276 | $ 286 |
Supplemental Cash Flow Inform86
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash paid for interest: | ||
Cash paid for interest, net of amounts capitalized | $ 87 | $ 91 |
Non-cash investing and financing activities: | ||
Property, plant and equipment acquired with accounts payable | 46 | 13 |
Other non-cash changes in property, plant and equipment | 0 | (2) |
Issuance of common and general partner units in the Transaction | 1,125 | 0 |
Deficit purchase price in the Transaction | $ 3,097 | $ 0 |
Condensed Consolidating Finan87
Condensed Consolidating Financial Information - Additional Information (Detail) | 3 Months Ended |
Mar. 31, 2017 | |
Parent Guarantor | |
Condensed Financial Statements, Captions [Line Items] | |
Ownership interest percentage in subsidiary | 100.00% |
Condensed Consolidating Finan88
Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2015 |
ASSETS | ||||
Cash and cash equivalents | $ 176 | $ 1 | $ 1 | $ 3 |
Accounts receivable, net | 651 | 792 | ||
Inventories | 64 | 72 | ||
Other | 89 | 129 | ||
Total current assets | 980 | 994 | ||
Property, plant and equipment, net | 9,047 | 9,069 | ||
Goodwill and intangible assets, net | 371 | 373 | ||
Advances receivable — consolidated subsidiaries | 0 | 0 | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Investments in unconsolidated affiliates | 2,988 | 2,969 | ||
Other long-term assets | 193 | 206 | ||
Total assets | 13,579 | 13,611 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable and other current liabilities | 890 | 1,123 | ||
Current maturities of long-term debt | 500 | 500 | ||
Advances payable — consolidated subsidiaries | 0 | 0 | ||
Long-term debt | 4,709 | 4,907 | ||
Other long-term liabilities | 230 | 228 | ||
Total liabilities | 6,329 | 6,758 | ||
Commitments and contingent liabilities | ||||
Equity: | ||||
Net equity | 7,229 | 6,829 | ||
Accumulated other comprehensive loss | (9) | (8) | ||
Total partners’ equity | 7,220 | 6,821 | ||
Noncontrolling interests | 30 | 32 | ||
Total equity | 7,250 | 6,853 | 7,084 | 7,092 |
Total liabilities and equity | 13,579 | 13,611 | ||
Reportable Legal Entities | Parent Guarantor | ||||
ASSETS | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Accounts receivable, net | 0 | 0 | ||
Inventories | 0 | 0 | ||
Other | 0 | 0 | ||
Total current assets | 0 | 0 | ||
Property, plant and equipment, net | 0 | 0 | ||
Goodwill and intangible assets, net | 0 | 0 | ||
Advances receivable — consolidated subsidiaries | 2,832 | 2,953 | ||
Investments in unconsolidated affiliates | 4,388 | 3,868 | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Other long-term assets | 0 | 0 | ||
Total assets | 7,220 | 6,821 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable and other current liabilities | 0 | 0 | ||
Current maturities of long-term debt | 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 | 7,220 | 6,821 | ||
Accumulated other comprehensive loss | 0 | 0 | ||
Total partners’ equity | 7,220 | 6,821 | ||
Noncontrolling interests | 0 | 0 | ||
Total equity | 7,220 | 6,821 | ||
Total liabilities and equity | 7,220 | 6,821 | ||
Reportable Legal Entities | Subsidiary Issuer | ||||
ASSETS | ||||
Cash and cash equivalents | 175 | 0 | 0 | 0 |
Accounts receivable, net | 0 | 0 | ||
Inventories | 0 | 0 | ||
Other | 0 | 0 | ||
Total current assets | 175 | 0 | ||
Property, plant and equipment, net | 0 | 0 | ||
Goodwill and intangible assets, net | 0 | 0 | ||
Advances receivable — consolidated subsidiaries | 2,297 | 2,760 | ||
Investments in unconsolidated affiliates | 7,182 | 6,587 | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Other long-term assets | 0 | 0 | ||
Total assets | 9,654 | 9,347 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable and other current liabilities | 57 | 72 | ||
Current maturities of long-term debt | 500 | 500 | ||
Advances payable — consolidated subsidiaries | 0 | 0 | ||
Long-term debt | 4,709 | 4,907 | ||
Other long-term liabilities | 0 | 0 | ||
Total liabilities | 5,266 | 5,479 | ||
Commitments and contingent liabilities | ||||
Equity: | ||||
Net equity | 4,392 | 3,871 | ||
Accumulated other comprehensive loss | (4) | (3) | ||
Total partners’ equity | 4,388 | 3,868 | ||
Noncontrolling interests | 0 | 0 | ||
Total equity | 4,388 | 3,868 | ||
Total liabilities and equity | 9,654 | 9,347 | ||
Reportable Legal Entities | Non-Guarantor Subsidiaries | ||||
ASSETS | ||||
Cash and cash equivalents | 1 | 1 | 1 | 3 |
Accounts receivable, net | 651 | 792 | ||
Inventories | 64 | 72 | ||
Other | 89 | 129 | ||
Total current assets | 805 | 994 | ||
Property, plant and equipment, net | 9,047 | 9,069 | ||
Goodwill and intangible assets, net | 371 | 373 | ||
Advances receivable — consolidated subsidiaries | 0 | 0 | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Investments in unconsolidated affiliates | 2,988 | 2,969 | ||
Other long-term assets | 193 | 206 | ||
Total assets | 13,404 | 13,611 | ||
LIABILITIES AND EQUITY | ||||
Accounts payable and other current liabilities | 833 | 1,051 | ||
Current maturities of long-term debt | 0 | 0 | ||
Advances payable — consolidated subsidiaries | 5,129 | 5,713 | ||
Long-term debt | 0 | 0 | ||
Other long-term liabilities | 230 | 228 | ||
Total liabilities | 6,192 | 6,992 | ||
Commitments and contingent liabilities | ||||
Equity: | ||||
Net equity | 7,187 | 6,592 | ||
Accumulated other comprehensive loss | (5) | (5) | ||
Total partners’ equity | 7,182 | 6,587 | ||
Noncontrolling interests | 30 | 32 | ||
Total equity | 7,212 | 6,619 | ||
Total liabilities and equity | 13,404 | 13,611 | ||
Consolidating Adjustments | ||||
ASSETS | ||||
Cash and cash equivalents | 0 | 0 | $ 0 | $ 0 |
Accounts receivable, net | 0 | 0 | ||
Inventories | 0 | 0 | ||
Other | 0 | 0 | ||
Total current assets | 0 | 0 | ||
Property, plant and equipment, net | 0 | 0 | ||
Goodwill and intangible assets, net | 0 | 0 | ||
Advances receivable — consolidated subsidiaries | (5,129) | (5,713) | ||
Investments in unconsolidated affiliates | (11,570) | (10,455) | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Other long-term assets | 0 | 0 | ||
Total assets | (16,699) | (16,168) | ||
LIABILITIES AND EQUITY | ||||
Accounts payable and other current liabilities | 0 | 0 | ||
Current maturities of long-term debt | 0 | 0 | ||
Advances payable — consolidated subsidiaries | (5,129) | (5,713) | ||
Long-term debt | 0 | 0 | ||
Other long-term liabilities | 0 | 0 | ||
Total liabilities | (5,129) | (5,713) | ||
Commitments and contingent liabilities | ||||
Equity: | ||||
Net equity | (11,570) | (10,455) | ||
Accumulated other comprehensive loss | 0 | 0 | ||
Total partners’ equity | (11,570) | (10,455) | ||
Noncontrolling interests | 0 | 0 | ||
Total equity | (11,570) | (10,455) | ||
Total liabilities and equity | $ (16,699) | $ (16,168) |
Condensed Consolidating Finan89
Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating revenues: | ||
Sales of natural gas and NGLs | $ 1,933 | $ 1,294 |
Transportation, processing and other | 157 | 152 |
Trading and marketing gains, net | 31 | 18 |
Total operating revenues | 2,121 | 1,464 |
Purchases of natural gas and NGLs | 1,687 | 1,135 |
Operating and maintenance expense | 167 | 179 |
Depreciation and amortization expense | 94 | 95 |
General and administrative expense | 62 | 62 |
Other expense (income), net | 10 | (87) |
Total operating costs and expenses | 2,020 | 1,384 |
Operating income | 101 | 80 |
Interest expense | (73) | (79) |
Income from consolidated subsidiaries | 0 | 0 |
Earnings from unconsolidated affiliates | 74 | 66 |
Income before income taxes | 102 | 67 |
Income tax expense | (1) | (2) |
Net income | 101 | 65 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 101 | 65 |
Reportable Legal Entities | Parent Guarantor | ||
Operating revenues: | ||
Sales of natural gas and NGLs | 0 | 0 |
Transportation, processing and other | 0 | 0 |
Trading and marketing gains, net | 0 | 0 |
Total operating revenues | 0 | 0 |
Purchases of natural gas and NGLs | 0 | 0 |
Operating and maintenance expense | 0 | 0 |
Depreciation and amortization expense | 0 | 0 |
General and administrative expense | 0 | 0 |
Other expense (income), net | 0 | 0 |
Total operating costs and expenses | 0 | 0 |
Operating income | 0 | 0 |
Interest expense | 0 | 0 |
Income from consolidated subsidiaries | 101 | 65 |
Earnings from unconsolidated affiliates | 0 | 0 |
Income before income taxes | 101 | 65 |
Income tax expense | 0 | 0 |
Net income | 101 | 65 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 101 | 65 |
Reportable Legal Entities | Subsidiary Issuer | ||
Operating revenues: | ||
Sales of natural gas and NGLs | 0 | 0 |
Transportation, processing and other | 0 | 0 |
Trading and marketing gains, net | 0 | 0 |
Total operating revenues | 0 | 0 |
Purchases of natural gas and NGLs | 0 | 0 |
Operating and maintenance expense | 0 | 0 |
Depreciation and amortization expense | 0 | 0 |
General and administrative expense | 0 | 0 |
Other expense (income), net | 0 | 0 |
Total operating costs and expenses | 0 | 0 |
Operating income | 0 | 0 |
Interest expense | (73) | (79) |
Income from consolidated subsidiaries | 174 | 144 |
Earnings from unconsolidated affiliates | 0 | 0 |
Income before income taxes | 101 | 65 |
Income tax expense | 0 | 0 |
Net income | 101 | 65 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 101 | 65 |
Reportable Legal Entities | Non-Guarantor Subsidiaries | ||
Operating revenues: | ||
Sales of natural gas and NGLs | 1,933 | 1,294 |
Transportation, processing and other | 157 | 152 |
Trading and marketing gains, net | 31 | 18 |
Total operating revenues | 2,121 | 1,464 |
Purchases of natural gas and NGLs | 1,687 | 1,135 |
Operating and maintenance expense | 167 | 179 |
Depreciation and amortization expense | 94 | 95 |
General and administrative expense | 62 | 62 |
Other expense (income), net | 10 | (87) |
Total operating costs and expenses | 2,020 | 1,384 |
Operating income | 101 | 80 |
Interest expense | 0 | 0 |
Income from consolidated subsidiaries | 0 | 0 |
Earnings from unconsolidated affiliates | 74 | 66 |
Income before income taxes | 175 | 146 |
Income tax expense | (1) | (2) |
Net income | 174 | 144 |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | 174 | 144 |
Consolidating Adjustments | ||
Operating revenues: | ||
Sales of natural gas and NGLs | 0 | 0 |
Transportation, processing and other | 0 | 0 |
Trading and marketing gains, net | 0 | 0 |
Total operating revenues | 0 | 0 |
Purchases of natural gas and NGLs | 0 | 0 |
Operating and maintenance expense | 0 | 0 |
Depreciation and amortization expense | 0 | 0 |
General and administrative expense | 0 | 0 |
Other expense (income), net | 0 | 0 |
Total operating costs and expenses | 0 | 0 |
Operating income | 0 | 0 |
Interest expense | 0 | 0 |
Income from consolidated subsidiaries | (275) | (209) |
Earnings from unconsolidated affiliates | 0 | 0 |
Income before income taxes | (275) | (209) |
Income tax expense | 0 | 0 |
Net income | (275) | (209) |
Net income attributable to noncontrolling interests | 0 | 0 |
Net income attributable to partners | $ (275) | $ (209) |
Condensed Consolidating Finan90
Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Condensed Financial Statements, Captions [Line Items] | ||
Net income | $ 101 | $ 65 |
Other comprehensive income (loss): | ||
Reclassification of cash flow hedge losses into earnings | 1 | 0 |
Other comprehensive income from consolidated subsidiaries | 0 | |
Total other comprehensive income | 1 | 0 |
Total comprehensive income | 102 | 65 |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | 102 | 65 |
Reportable Legal Entities | Parent Guarantor | ||
Condensed Financial Statements, Captions [Line Items] | ||
Net income | 101 | 65 |
Other comprehensive income (loss): | ||
Reclassification of cash flow hedge losses into earnings | 0 | |
Other comprehensive income from consolidated subsidiaries | 1 | |
Total other comprehensive income | 1 | 0 |
Total comprehensive income | 102 | 65 |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | 102 | 65 |
Reportable Legal Entities | Subsidiary Issuer | ||
Condensed Financial Statements, Captions [Line Items] | ||
Net income | 101 | 65 |
Other comprehensive income (loss): | ||
Reclassification of cash flow hedge losses into earnings | 1 | |
Other comprehensive income from consolidated subsidiaries | 0 | |
Total other comprehensive income | 1 | 0 |
Total comprehensive income | 102 | 65 |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | 102 | 65 |
Reportable Legal Entities | Non-Guarantor Subsidiaries | ||
Condensed Financial Statements, Captions [Line Items] | ||
Net income | 174 | 144 |
Other comprehensive income (loss): | ||
Reclassification of cash flow hedge losses into earnings | 0 | |
Other comprehensive income from consolidated subsidiaries | 0 | |
Total other comprehensive income | 0 | 0 |
Total comprehensive income | 174 | 144 |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | 174 | 144 |
Consolidating Adjustments | ||
Condensed Financial Statements, Captions [Line Items] | ||
Net income | (275) | (209) |
Other comprehensive income (loss): | ||
Reclassification of cash flow hedge losses into earnings | 0 | |
Other comprehensive income from consolidated subsidiaries | (1) | |
Total other comprehensive income | (1) | 0 |
Total comprehensive income | (276) | (209) |
Total comprehensive income attributable to noncontrolling interests | 0 | 0 |
Total comprehensive income attributable to partners | $ (276) | $ (209) |
Condensed Consolidating Finan91
Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
OPERATING ACTIVITIES | ||
Net cash (used in) provided by operating activities | $ 144 | $ 151 |
INVESTING ACTIVITIES: | ||
Intercompany transfers | 0 | 0 |
Capital expenditures | (48) | (57) |
Investments in unconsolidated affiliates | (20) | (12) |
Change in restricted cash | 0 | (7) |
Net cash used in investing activities | (68) | (76) |
FINANCING ACTIVITIES: | ||
Intercompany transfers | 0 | 0 |
Proceeds from long-term debt | 0 | 892 |
Payments of long-term debt | (195) | (896) |
Net change in advances to predecessor from DCP Midstream, LLC | 418 | 50 |
Distributions to limited partners and general partner | (121) | (121) |
Distributions to noncontrolling interests | (2) | (2) |
Other | (1) | 0 |
Net cash provided by (used in) financing activities | 99 | (77) |
Net change in cash and cash equivalents | 175 | (2) |
Cash and cash equivalents, beginning of period | 1 | 3 |
Cash and cash equivalents, end of period | 176 | 1 |
Reportable Legal Entities | Parent Guarantor | ||
OPERATING ACTIVITIES | ||
Net cash (used in) provided by operating activities | 0 | 0 |
INVESTING ACTIVITIES: | ||
Intercompany transfers | 121 | 121 |
Capital expenditures | 0 | 0 |
Investments in unconsolidated affiliates | 0 | 0 |
Change in restricted cash | 0 | |
Net cash used in investing activities | 121 | 121 |
FINANCING ACTIVITIES: | ||
Intercompany transfers | 0 | 0 |
Proceeds from long-term debt | 0 | |
Payments of long-term debt | 0 | 0 |
Net change in advances to predecessor from DCP Midstream, LLC | 0 | 0 |
Distributions to limited partners and general partner | (121) | (121) |
Distributions to noncontrolling interests | 0 | 0 |
Other | 0 | |
Net cash provided by (used in) financing activities | (121) | (121) |
Net change in cash and cash equivalents | 0 | 0 |
Cash and cash equivalents, beginning of period | 0 | 0 |
Cash and cash equivalents, end of period | 0 | 0 |
Reportable Legal Entities | Subsidiary Issuer | ||
OPERATING ACTIVITIES | ||
Net cash (used in) provided by operating activities | (87) | (92) |
INVESTING ACTIVITIES: | ||
Intercompany transfers | 458 | 103 |
Capital expenditures | 0 | 0 |
Investments in unconsolidated affiliates | 0 | 0 |
Change in restricted cash | (7) | |
Net cash used in investing activities | 458 | 96 |
FINANCING ACTIVITIES: | ||
Intercompany transfers | 0 | 0 |
Proceeds from long-term debt | 892 | |
Payments of long-term debt | (195) | (896) |
Net change in advances to predecessor from DCP Midstream, LLC | 0 | 0 |
Distributions to limited partners and general partner | 0 | 0 |
Distributions to noncontrolling interests | 0 | 0 |
Other | (1) | |
Net cash provided by (used in) financing activities | (196) | (4) |
Net change in cash and cash equivalents | 175 | 0 |
Cash and cash equivalents, beginning of period | 0 | 0 |
Cash and cash equivalents, end of period | 175 | 0 |
Reportable Legal Entities | Non-Guarantor Subsidiaries | ||
OPERATING ACTIVITIES | ||
Net cash (used in) provided by operating activities | 231 | 243 |
INVESTING ACTIVITIES: | ||
Intercompany transfers | 0 | 0 |
Capital expenditures | (48) | (57) |
Investments in unconsolidated affiliates | (20) | (12) |
Change in restricted cash | 0 | |
Net cash used in investing activities | (68) | (69) |
FINANCING ACTIVITIES: | ||
Intercompany transfers | (579) | (224) |
Proceeds from long-term debt | 0 | |
Payments of long-term debt | 0 | 0 |
Net change in advances to predecessor from DCP Midstream, LLC | 418 | 50 |
Distributions to limited partners and general partner | 0 | 0 |
Distributions to noncontrolling interests | (2) | (2) |
Other | 0 | |
Net cash provided by (used in) financing activities | (163) | (176) |
Net change in cash and cash equivalents | 0 | (2) |
Cash and cash equivalents, beginning of period | 1 | 3 |
Cash and cash equivalents, end of period | 1 | 1 |
Consolidating Adjustments | ||
OPERATING ACTIVITIES | ||
Net cash (used in) provided by operating activities | 0 | 0 |
INVESTING ACTIVITIES: | ||
Intercompany transfers | (579) | (224) |
Capital expenditures | 0 | 0 |
Investments in unconsolidated affiliates | 0 | 0 |
Change in restricted cash | 0 | |
Net cash used in investing activities | (579) | (224) |
FINANCING ACTIVITIES: | ||
Intercompany transfers | 579 | 224 |
Proceeds from long-term debt | 0 | |
Payments of long-term debt | 0 | 0 |
Net change in advances to predecessor from DCP Midstream, LLC | 0 | 0 |
Distributions to limited partners and general partner | 0 | 0 |
Distributions to noncontrolling interests | 0 | 0 |
Other | 0 | |
Net cash provided by (used in) financing activities | 579 | 224 |
Net change in cash and cash equivalents | 0 | 0 |
Cash and cash equivalents, beginning of period | 0 | 0 |
Cash and cash equivalents, end of period | $ 0 | $ 0 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Detail) - Subsequent Event | Apr. 25, 2017$ / shares |
Subsequent Event [Line Items] | |
Distribution of dividend (in dollars per share) | $ 0.78 |
Distribution payable date | May 15, 2017 |
Distribution record date | May 9, 2017 |
Uncategorized Items - dpm-20170
Label | Element | Value |
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest | $ (3,000,000) |
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest | (3,000,000) |
Foreign Currency Derivatives [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest | 1,000,000 |
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest | $ 1,000,000 |