Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 12, 2018 | Jun. 30, 2017 | |
Document and Entity Information | |||
Entity Registrant Name | PLAINS ALL AMERICAN PIPELINE LP | ||
Entity Central Index Key | 1,070,423 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 11.3 | ||
Entity Common Stock Outstanding (shares) | 725,206,904 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 37 | $ 47 |
Trade accounts receivable and other receivables, net | 3,029 | 2,279 |
Inventory | 713 | 1,343 |
Other current assets | 221 | 603 |
Total current assets | 4,000 | 4,272 |
PROPERTY AND EQUIPMENT | 16,862 | 16,220 |
Accumulated depreciation | (2,773) | (2,348) |
Property and equipment, net | 14,089 | 13,872 |
OTHER ASSETS | ||
Goodwill | 2,566 | 2,344 |
Investments in unconsolidated entities | 2,756 | 2,343 |
Linefill and base gas | 872 | 896 |
Long-term inventory | 164 | 193 |
Other long-term assets, net | 904 | 290 |
Total assets | 25,351 | 24,210 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 3,457 | 2,588 |
Short-term debt | 737 | 1,715 |
Other current liabilities | 337 | 361 |
Total current liabilities | 4,531 | 4,664 |
LONG-TERM LIABILITIES | ||
Senior notes, net of unamortized discounts and debt issuance costs | 8,933 | 9,874 |
Other long-term debt | 250 | 250 |
Other long-term liabilities and deferred credits | 679 | 606 |
Total long-term liabilities | 9,862 | 10,730 |
COMMITMENTS AND CONTINGENCIES (NOTE 17) | ||
PARTNERS’ CAPITAL | ||
Total partners’ capital excluding noncontrolling interests | 10,958 | 8,759 |
Noncontrolling interests | 57 | |
Total partners’ capital | 10,958 | 8,816 |
Total liabilities and partners’ capital | 25,351 | 24,210 |
Series A Preferred Units | ||
PARTNERS’ CAPITAL | ||
Unitholders | 1,505 | 1,508 |
Series B Preferred Units | ||
PARTNERS’ CAPITAL | ||
Unitholders | 788 | |
Common Units | ||
PARTNERS’ CAPITAL | ||
Unitholders | $ 8,665 | $ 7,251 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2017 | Dec. 31, 2016 |
Series A Preferred Units | ||
Units outstanding (in units) | 69,696,542 | 64,388,853 |
Series B Preferred Units | ||
Units outstanding (in units) | 800,000 | |
Common Units | ||
Units outstanding (in units) | 725,189,138 | 669,194,419 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
REVENUES | |||
Supply and Logistics segment revenues | $ 25,056 | $ 19,004 | $ 21,927 |
Transportation segment revenues | 612 | 632 | 697 |
Facilities segment revenues | 555 | 546 | 528 |
Total revenues | 26,223 | 20,182 | 23,152 |
COSTS AND EXPENSES | |||
Purchases and related costs | 22,985 | 17,233 | 19,726 |
Field operating costs | 1,183 | 1,182 | 1,454 |
General and administrative expenses | 276 | 279 | 278 |
Depreciation and amortization | 626 | 494 | 432 |
Total costs and expenses | 25,070 | 19,188 | 21,890 |
OPERATING INCOME | 1,153 | 994 | 1,262 |
OTHER INCOME/(EXPENSE) | |||
Equity earnings in unconsolidated entities | 290 | 195 | 183 |
Interest expense (net of capitalized interest of $35, $47 and $57, respectively) | (510) | (467) | (432) |
Other income/(expense), net | (31) | 33 | (7) |
INCOME BEFORE TAX | 902 | 755 | 1,006 |
Current income tax expense | (28) | (85) | (84) |
Deferred income tax (expense)/benefit | (16) | 60 | (16) |
NET INCOME | 858 | 730 | 906 |
Net income attributable to noncontrolling interests | (2) | (4) | (3) |
NET INCOME ATTRIBUTABLE TO PAA | 856 | 726 | 903 |
NET INCOME PER COMMON UNIT (NOTE 3): | |||
Net income allocated to common unitholders — Basic | 685 | 200 | 305 |
Net income allocated to common unitholders — Diluted | $ 685 | $ 200 | $ 305 |
Common Units | |||
NET INCOME PER COMMON UNIT (NOTE 3): | |||
Basic weighted average common units outstanding (in units) | 717 | 464 | 394 |
Basic net income per common unit (in dollars per unit) | $ 0.96 | $ 0.43 | $ 0.78 |
Diluted weighted average common units outstanding (in units) | 718 | 466 | 396 |
Diluted net income per common unit (in dollars per unit) | $ 0.95 | $ 0.43 | $ 0.77 |
CONSOLIDATED STATEMENTS OF OPE5
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Capitalized interest | $ 35 | $ 47 | $ 57 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net income | $ 858 | $ 730 | $ 906 |
Other comprehensive income/(loss) | 239 | 72 | (614) |
Comprehensive income | 1,097 | 802 | 292 |
Comprehensive income attributable to noncontrolling interests | (2) | (4) | (3) |
Comprehensive income attributable to PAA | $ 1,095 | $ 798 | $ 289 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Total period activity | $ 239 | $ 72 | $ (614) |
Derivative Instruments | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Beginning balance | (228) | (203) | (159) |
Reclassification adjustments | 21 | 8 | (45) |
Deferred gain/(loss) on cash flow hedges | (16) | (33) | 1 |
Total period activity | 5 | (25) | (44) |
Ending balance | (223) | (228) | (203) |
Translation Adjustments | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Beginning balance | (782) | (878) | (308) |
Currency translation adjustments | 234 | 96 | (570) |
Total period activity | 234 | 96 | (570) |
Ending balance | (548) | (782) | (878) |
Other | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Beginning balance | 1 | 0 | 0 |
Other | 1 | ||
Total period activity | 1 | ||
Ending balance | 1 | 1 | 0 |
Total | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Beginning balance | (1,009) | (1,081) | (467) |
Reclassification adjustments | 21 | 8 | (45) |
Deferred gain/(loss) on cash flow hedges | (16) | (33) | 1 |
Currency translation adjustments | 234 | 96 | (570) |
Other | 1 | ||
Total period activity | 239 | 72 | (614) |
Ending balance | $ (770) | $ (1,009) | $ (1,081) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income | $ 858 | $ 730 | $ 906 |
Reconciliation of net income to net cash provided by operating activities: | |||
Depreciation and amortization | 626 | 494 | 432 |
Equity-indexed compensation expense | 41 | 60 | 27 |
Inventory valuation adjustments (Note 4) | 35 | 3 | 117 |
Deferred income tax expense/(benefit) | 16 | (60) | 16 |
Settlement of terminated interest rate hedging instruments | (29) | (29) | (48) |
Change in fair value of Preferred Distribution Rate Reset Option (Note 12) | (13) | (30) | |
Equity earnings in unconsolidated entities | (290) | (195) | (183) |
Distributions from unconsolidated entities | 304 | 216 | 214 |
Other | 10 | 23 | (21) |
Changes in assets and liabilities, net of acquisitions: | |||
Trade accounts receivable and other | (511) | (524) | 803 |
Inventory | 605 | (463) | (90) |
Accounts payable and other current liabilities | 847 | 508 | (815) |
Net cash provided by operating activities | 2,499 | 733 | 1,358 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Cash paid in connection with acquisitions, net of cash acquired (Note 6) | (1,280) | (282) | (105) |
Investments in unconsolidated entities (Note 8) | (416) | (301) | (253) |
Additions to property, equipment and other | (1,024) | (1,334) | (2,079) |
Proceeds from sales of assets (Note 6) | 1,083 | 654 | 5 |
Return of investment from unconsolidated entities (Note 8) | 21 | ||
Cash received from sales of linefill and base gas | 49 | 1 | |
Cash paid for purchases of linefill and base gas | (2) | (7) | (133) |
Other investing activities | (1) | (3) | 34 |
Net cash used in investing activities | (1,570) | (1,273) | (2,530) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net borrowings/(repayments) under commercial paper program (Note 10) | (690) | (564) | 631 |
Net borrowings under senior secured hedged inventory facility (Note 10) | 36 | 447 | 300 |
Repayment under AAP senior secured revolving credit facility (Note 10) | (92) | ||
Repayment of AAP term loan (Note 10) | (550) | ||
Proceeds from the issuance of senior notes (Note 10) | 748 | 998 | |
Repayments of senior notes (Note 10) | (1,350) | (175) | (549) |
Net proceeds from the sale of Series A preferred units (Note 11) | 1,569 | ||
Net proceeds from the sale of Series B preferred units (Note 11) | 788 | ||
Net proceeds from the sale of common units (Note 11) | 1,664 | 796 | 1,099 |
Contributions from general partner | 42 | 23 | |
Distributions paid to common unitholders (Note 11) | (1,386) | (1,062) | (1,081) |
Distributions paid to general partner (Note 11) | (565) | (590) | |
Other financing activities | (5) | (38) | (31) |
Net cash provided by/(used in) financing activities | (943) | 556 | 800 |
Effect of translation adjustment on cash | 4 | 4 | (4) |
Net increase/(decrease) in cash and cash equivalents | (10) | 20 | (376) |
Cash and cash equivalents, beginning of period | 47 | 27 | 403 |
Cash and cash equivalents, end of period | 37 | 47 | 27 |
Cash paid for: | |||
Interest, net of amounts capitalized | 486 | 450 | 396 |
Income taxes, net of amounts refunded | $ 50 | $ 98 | $ 50 |
CONSOLIDATED STATEMENTS OF CHA9
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Total | Partners’ Capital Excluding Noncontrolling Interests | Noncontrolling Interests | General PartnerPartners’ Capital Excluding Noncontrolling Interests | Series A Preferred UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests | Series B Preferred UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests | Common Units | Common UnitsLimited PartnersPartners’ Capital Excluding Noncontrolling Interests |
Balance, beginning of period at Dec. 31, 2014 | $ 8,191 | $ 8,133 | $ 58 | $ 340 | $ 0 | $ 0 | $ 7,793 | |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||
Net income | 906 | 903 | 3 | 589 | 314 | |||
Distributions (Note 11) | (1,674) | (1,671) | (3) | (590) | (1,081) | |||
Sales of common units | 1,121 | 1,121 | 22 | $ 1,121 | 1,099 | |||
Other comprehensive income/(loss) | (614) | (614) | (12) | (602) | ||||
Other | 9 | 9 | (48) | 57 | ||||
Balance, end of period at Dec. 31, 2015 | 7,939 | 7,881 | 58 | 301 | 0 | 0 | 7,580 | |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||
Net income | 730 | 726 | 4 | 393 | 333 | |||
Distributions (Note 11) | (1,631) | (1,627) | (4) | (565) | (1,062) | |||
Sale of Series A preferred units | 1,542 | 1,542 | 33 | 1,509 | ||||
Sales of common units | 805 | 805 | 9 | 796 | ||||
Other comprehensive income/(loss) | 72 | 72 | 0 | 72 | ||||
Simplification Transactions (Note 1) | (642) | (642) | (171) | (471) | ||||
Other | 1 | 2 | (1) | (1) | 3 | |||
Balance, end of period at Dec. 31, 2016 | 8,816 | 8,759 | 57 | 0 | 1,508 | 0 | 7,251 | |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||
Net income | 858 | 856 | 2 | 0 | 11 | 845 | ||
Distributions (Note 11) | (1,399) | (1,397) | (2) | 0 | (11) | (1,386) | ||
Sale of Series B preferred units | 788 | 788 | 788 | |||||
Sales of common units | 1,664 | 1,664 | 0 | $ 1,664 | 1,664 | |||
Acquisition of interest in Advantage Joint Venture (Note 6) | 40 | 40 | 40 | |||||
Sale of interest in SLC Pipeline LLC (Note 6) | (57) | (57) | ||||||
Other comprehensive income/(loss) | 239 | 239 | 239 | |||||
Other | 9 | 9 | 0 | (3) | 12 | |||
Balance, end of period at Dec. 31, 2017 | $ 10,958 | $ 10,958 | $ 0 | $ 0 | $ 1,505 | $ 788 | $ 8,665 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Consolidation and Presentation | Organization and Basis of Consolidation and Presentation Organization Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries. We own and operate midstream energy infrastructure and provide logistics services primarily for crude oil, natural gas liquids (“NGL”) and natural gas. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 19 for further discussion of our operating segments. Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of December 31, 2017 , AAP also owned a limited partner interest in us through its ownership of approximately 284.0 million of our common units (approximately 36% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at December 31, 2017 , owned an approximate 55% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP. As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to the “PAGP Entities” include PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to our “general partner,” as the context requires, include any or all of the PAGP Entities. References to the “Plains Entities” include us, our subsidiaries and the PAGP Entities. Simplification Transactions On November 15, 2016, the Plains Entities closed a series of transactions and executed several organizational and ancillary documents (the “Simplification Transactions”) intended to simplify our capital structure, better align the interests of our stakeholders and improve our overall credit profile. The Simplification Transactions included, among other things: • the permanent elimination of our incentive distribution rights (“IDRs”) and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of 245.5 million PAA common units (including approximately 0.8 million units to be issued in the future) and the assumption by us of all of AAP’s outstanding debt ( $642 million ); • the implementation of a unified governance structure pursuant to which the board of directors of GP LLC was eliminated and an expanded board of directors of PAGP GP assumed oversight responsibility over both us and PAGP; • the provision for annual PAGP shareholder elections beginning in 2018 for the purpose of electing certain directors, and the participation of our common unitholders and Series A preferred unitholders in such elections through our ownership of Class C shares in PAGP, which provide us, as the sole holder of such Class C shares, the right to vote in elections of eligible PAGP directors together with the holders of PAGP Class A and Class B shares; • the execution by AAP of a reverse split to adjust the number of AAP Class A units (“AAP units”) such that the number of outstanding AAP units (assuming the conversion of AAP Class B units (the “AAP Management Units”) into AAP units) equaled the number of our common units received by AAP at the closing of the Simplification Transactions. Simultaneously, PAGP executed reverse splits to adjust the number of (i) PAGP Class A shares outstanding to equal the number of AAP units it owned following AAP’s reverse unit split and (ii) PAGP Class B shares outstanding to equal the number of AAP units owned by AAP’s unitholders other than PAGP following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our common unitholders and PAGP’s Class A shareholders, such that the number of outstanding PAGP Class A shares equals the number of AAP units owned by PAGP, which in turn equals the number of our common units held by AAP that are attributable to PAGP’s interest in AAP. The Plains Entities also entered into an Omnibus Agreement, pursuant to which such one-to-one relationship will be maintained subsequent to the closing of the Simplification Transactions; and • the creation of a right for certain holders of the AAP units to cause AAP to redeem such AAP units in exchange for an equal number of our common units held by AAP. The Simplification Transactions were between and among consolidated subsidiaries of PAGP that are considered entities under common control. These equity transactions did not result in a change in the carrying value of the underlying assets and liabilities. Definitions Additional defined terms are used in the following notes and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) ASC = Accounting Standards Codification ASU = Accounting Standards Update Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar DERs = Distribution equivalent rights EBITDA = Earnings before interest, taxes, depreciation and amortization EPA = United States Environmental Protection Agency FASB = Financial Accounting Standards Board GAAP = Generally accepted accounting principles in the United States ICE = Intercontinental Exchange IPO = Initial public offering LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet MLP = Master limited partnership NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange Oxy = Occidental Petroleum Corporation or its subsidiaries PLA = Pipeline loss allowance USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2017 and 2016 , and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2017 , 2016 and 2015 . All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) impairment assessments of goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, (v) equity-indexed compensation plan accruals, (vi) property and equipment, depreciation and amortization expense, asset retirement obligations and impairments, (vii) allowance for doubtful accounts and (viii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates. Revenue Recognition Supply and Logistics Segment Revenues. Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges. The sales under these exchanges are netted to zero in Supply and Logistics segment revenues in our Consolidated Statements of Operations. Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting. Transportation Segment Revenues. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff, as well as revenues associated with agreements for committed space on various assets. Tariff revenues are recognized when the service is provided pursuant to specifications outlined in the tariffs. Revenues associated with fees are recognized in the month to which the fee applies. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the allowance volumes and actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) in the month of occurrence. Facilities Segment Revenues. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services and (vi) loading and unloading fees at our rail terminals. We generate revenue through a combination of month-to-month and multi-year agreements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from NGL fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. Minimum Volume Commitments. We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. At December 31, 2017 and 2016 , counterparty deficiencies associated with agreements that include minimum volume commitments totaled $57 million and $66 million , respectively, of which $37 million and $54 million , respectively, was recorded as deferred revenue. The remaining balance of $20 million and $12 million at each respective date was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Consolidated Financial Statements as we had not yet billed or collected such amounts. Purchases and Related Costs Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for storage and transportation, whether by pipeline, truck, rail, ship or barge and (iii) performance-related bonus costs. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us. Purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations. Field Operating Costs and General and Administrative Expenses Field operating costs consist of various field operating expenses, including payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; certain information systems and legal costs; office rent; contract and consultant costs; and audit and tax fees. Foreign Currency Transactions/Translation Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheets. Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the Consolidated Statements of Operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a net gain of $21 million for the year ended December 31, 2017 , a net loss of $8 million for the year ended December 31, 2016 and a net gain of $21 million for the year ended December 31, 2015 . Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2017 and 2016 , accounts payable included $60 million and $66 million , respectively, of outstanding checks that were reclassified from cash and cash equivalents. Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. Prices for crude oil, natural gas and NGLs can fluctuate widely. For example, NYMEX West Texas Intermediate oil prices have been volatile and ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Although prices recovered somewhat in 2017 to close the year at $60.42 per barrel, the sustained decrease in commodity prices since late 2014 has caused liquidity and leverage issues throughout the energy industry, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of December 31, 2017 and 2016 , we had received $117 million and $89 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $54 million and $66 million as of December 31, 2017 and 2016 , respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for the majority of our net-cash arrangements. We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2017 and 2016 , substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $3 million at both December 31, 2017 and 2016 . Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. Noncontrolling Interests Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Following our sale of SLC Pipeline LLC in the fourth quarter of 2017, we no longer have any noncontrolling interests in consolidated subsidiaries. See Note 11 for additional discussion regarding our noncontrolling interests. Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily related to our Transportation and Facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was $103 million and $44 million , respectively, at December 31, 2017 and 2016 and were primarily reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets. Fair Value Measurements Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels. The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest rate derivatives and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period. See Note 12 for further discussion. Other Significant Accounting Policies See the respective footnotes for our accounting policies regarding (i) net income per common unit, (ii) inventory, linefill and base gas and long-term inventory, (iii) property and equipment, (iv) acquisitions, (v) goodwill, (vi) investments in unconsolidated entities, (vii) other long-term assets, net, (viii) income allocation for partners’ capital presentation purposes,(ix) derivatives and risk management activities, (x) income taxes, (xi) equity-indexed compensation and (xii) legal and environmental matters. Recent Accounting Pronouncements In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We expect to adopt this ASU on January 1, 2019 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows. In May 2017, the FASB issued ASU 2017-09, Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Under the new guidance, modification accounting is required only if the fair value (or calculated value or intrinsic value, if such alternative method is used), the vesting conditions, or the classification of the award (equity or liability) changes as a result of the change in terms or conditions. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . The ASU clarifies what type of transactions involving nonfinancial assets are covered by the ASU and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606. We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of approximately $110 million related to the retained non-controlling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017. See Note 8 for discussion of our investments in unconsolidated entities. In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The amendments within this ASU eliminate Step 2 from the goodwill impairment test, which currently requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Under the amended standard, goodwill impairment will instead be measured using Step 1 of the goodwill impairment test with goodwill impairment being equal to the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in the first quarter of 2017 and applied the amended standard to our 2017 annual goodwill impairment test. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which improves the guidance for determining whether a transaction involves the purchase or disposal of a business or an asset. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We adopted this ASU on January 1, 2018 and will apply the new guidance to applicable transactions occurring after that date. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) , requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 31, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our statement of cash flows. In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory , to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted in the first interim period of an annual reporting period. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control , changing how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This guidance was effective for interim and annual periods beginning after December 31, 2016. We adopted this ASU on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this ASU on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position results of operations and cash flows. In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which simplified several aspects of the accounting for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This ASU is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted the applicable provisions of the ASU on January 1, 2017 and (i) elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption and (ii) classify cash paid for taxes when directly withholding units from an employee’s award for tax-withholding purposes as a financing activity on our Consolidated Statement of Cash Flows. Our adoption did not have a material impact on our financial position or results of operations for the periods presented. We reclassified approximately $7 million and $14 million , respectively, of cash outflows from operating activities to financing activities for the years ended December 31, 2016 and 2015 related to cash paid for minimum statutory withholding requirements for which we withheld units from employees’ awards. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This ASU will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this ASU on January 1, 2019. We are currently evaluating the effect that adopting this ASU will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our Consolidated Balance Sheet. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires entities to measure inventory at the lower of cost and net realizable value; however, inventory measured using last-in, first-out and the retail inventory method is unchanged by this ASU. This guidance was effective for interim and annual periods beginning after December 15, 2016, with prospective application required. We adopted this ASU on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, followed by a series of related accounting standard updates (collectively referred to as “Topic 606”) with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. Topic 606 also requires additional disclosures. Topic 606 can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption and is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting Topic 606 on each type of revenue contract entered into with customers, and our implementation team effected changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We did not identify any material revenue recognition timing differences under Topic 606 as compared to our policies in effect prior to adoption. In addition, we will have an increase in disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. The cumulative effect of the adoption of Topic 606 was not material. |
Net Income Per Common Unit
Net Income Per Common Unit | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income Per Common Unit | Net Income Per Common Unit After consideration of distributions to preferred unitholders (whether paid in cash or in-kind), basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our general partner (for periods prior to the Simplification Transactions), limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units and the assumption by us of AAP’s debt. In addition, we may issue to AAP up to 0.8 million common units in connection with certain AAP Management Units becoming earned in future periods. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. See Note 1 for additional discussion of the Simplification Transactions. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities, and for periods prior to the closing of the Simplification Transactions, the 2% general partner’s interest and IDRs) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units, (ii) our LTIP awards and (iii) common units that are issuable to AAP when certain AAP Management Units become earned. See Note 11 for additional information regarding our Series A preferred units. See Note 16 for a complete discussion of our LTIP awards and the AAP Management Units. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the years ended December 31, 2017 and 2016 as the effect was antidilutive. Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that were deemed to be dilutive during the three years ended December 31, 2017 were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. As none of the necessary conditions for the remaining AAP Management Units to become earned had been satisfied by December 31, 2017 , no common units issuable to AAP were contemplated in the calculation of diluted net income per common unit for any period presented. The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2017 2016 2015 Basic Net Income per Common Unit Net income attributable to PAA $ 856 $ 726 $ 903 Distributions to Series A preferred unitholders (142 ) (122 ) — Distributions to Series B preferred unitholders (11 ) — — Distributions to general partner — (412 ) (608 ) Distributions to participating securities (2 ) (4 ) (6 ) Undistributed loss allocated to general partner — 14 16 Other (16 ) (2 ) — Net income allocated to common unitholders (1) $ 685 $ 200 $ 305 Basic weighted average common units outstanding (2) 717 464 394 Basic net income per common unit $ 0.96 $ 0.43 $ 0.78 Diluted Net Income per Common Unit Net income attributable to PAA $ 856 $ 726 $ 903 Distributions to Series A preferred unitholders (142 ) (122 ) — Distributions to Series B preferred unitholders (11 ) — — Distributions to general partner — (412 ) (608 ) Distributions to participating securities (2 ) (4 ) (6 ) Undistributed loss allocated to general partner — 14 16 Other (16 ) (2 ) — Net income allocated to common unitholders (1) $ 685 $ 200 $ 305 Basic weighted average common units outstanding (2) 717 464 394 Effect of dilutive securities: LTIP units 1 2 2 Diluted weighted average common units outstanding 718 466 396 Diluted net income per common unit $ 0.95 $ 0.43 $ 0.77 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) We considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders. |
Inventory, Linefill and Base Ga
Inventory, Linefill and Base Gas and Long-term Inventory | 12 Months Ended |
Dec. 31, 2017 | |
Inventory, Linefill and Base Gas and Long-term Inventory | |
Inventory, Linefill and Base Gas and Long-term Inventory | Inventory, Linefill and Base Gas and Long-term Inventory Inventory primarily consists of crude oil, NGL and natural gas in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. During the years ended December 31, 2017 , 2016 and 2015 , we recorded charges of $35 million , $3 million and $117 million , respectively, related to the writedown of our crude oil, NGL and natural gas inventory due to declines in prices. A portion of these inventory valuation adjustments was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil and NGL inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statement of Operations. See Note 12 for discussion of our derivative and risk management activities. Linefill and base gas in assets we own are recorded at historical cost and consist of crude oil, NGL and natural gas. We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks and caverns that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 5 for further discussion regarding impairment of long-lived assets. During 2017 , 2016 and 2015 , we did not recognize any impairments of linefill and base gas. Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at the average cost of the applicable inventory pools, and into long-term inventory, which is reflected as a separate line item in “Other assets” on our Consolidated Balance Sheets. Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): December 31, 2017 December 31, 2016 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 7,800 barrels $ 402 $ 51.54 23,589 barrels $ 1,049 $ 44.47 NGL 10,774 barrels 294 $ 27.29 13,497 barrels 242 $ 17.93 Natural gas — Mcf — $ — 14,540 Mcf 32 $ 2.20 Other N/A 17 N/A N/A 20 N/A Inventory subtotal 713 1,343 Linefill and base gas Crude oil 12,340 barrels 719 $ 58.27 12,273 barrels 710 $ 57.85 NGL 1,597 barrels 45 $ 28.18 1,660 barrels 45 $ 27.11 Natural gas 24,976 Mcf 108 $ 4.32 30,812 Mcf 141 $ 4.58 Linefill and base gas subtotal 872 896 Long-term inventory Crude oil 1,870 barrels 105 $ 56.15 3,279 barrels 163 $ 49.71 NGL 2,167 barrels 59 $ 27.23 1,418 barrels 30 $ 21.16 Long-term inventory subtotal 164 193 Total $ 1,749 $ 2,432 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized. We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. For the years ended December 31, 2017 , 2016 and 2015 , capitalized interest recorded to property and equipment was $17 million , $34 million and $49 million , respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 8 for additional information. We also capitalize expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred. Property and equipment, net is stated at cost and consisted of the following (in millions): Estimated Useful Lives (Years) December 31, 2017 2016 Pipelines and related facilities (1) 10 - 70 $ 9,585 $ 9,025 Storage, terminal and rail facilities 30 - 70 5,558 5,305 Trucking equipment and other 3 - 15 414 408 Construction in progress — 610 826 Office property and equipment 2 - 50 255 222 Land and other N/A 440 434 Property and equipment, gross 16,862 16,220 Accumulated depreciation (2,773 ) (2,348 ) Property and equipment, net $ 14,089 $ 13,872 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2017 , 2016 and 2015 was $463 million , $470 million and $380 million , respectively (including amounts related to the discontinuation of certain capital projects). We also classify gains and losses on sales of assets and asset impairments as a component of “Depreciation and amortization” in our Consolidated Statements of Operations. See Note 6 for a discussion of our disposition activities. See “ Impairment of Long-Lived Assets ” below for a discussion of our policy for the recognition of asset impairments. Impairment of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include: • whether there is an indication of impairment; • the grouping of assets; • the intention of “holding,” “abandoning” or “selling” an asset; • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and • if an impairment exists, the fair value of the asset or asset group. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods. During the years ended December 31, 2017 and 2016, we recognized $152 million and $80 million , respectively, of non-cash charges related to the write-down of certain of our long-lived rail and other terminal assets included in our Facilities segment due to asset impairments and accelerated depreciation. Such charges are reflected in “Depreciation and amortization” on our Consolidated Financial Statements. The decline in demand for movements of crude oil by rail in the United States due to sustained unfavorable market conditions resulted in expected decreases in future cash flows for certain of our rail terminal assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of our impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair values were based upon recent sales prices of comparable facilities, as well as management’s expectation of the market values for such assets based on their industry experience. We consider such inputs to be a Level 3 input in the fair value hierarchy. We did no t recognize any impairments during the year ended December 31, 2015. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | Acquisitions and Dispositions The following acquisitions, excluding acquired interests accounted for under the equity method of accounting mentioned specifically below, were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance. Acquisitions 2017 Alpha Crude Connector Acquisition On February 14, 2017, we acquired all of the issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration of approximately $1.215 billion , subject to working capital and other adjustments (the “ACC Acquisition”). The ACC Acquisition was initially funded through borrowings under our senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from our March 2017 issuance of common units to AAP pursuant to the Omnibus Agreement and in connection with a PAGP underwritten equity offering. See Note 11 for additional information. Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as the “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises approximately 515 miles of gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink. During 2017, we made additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements to increase the ACC System capacity to approximately 350,000 barrels per day, depending on the level of volume at each delivery point. The ACC System is supported by acreage dedications covering approximately 315,000 gross acres, including a significant acreage dedication from one of the largest producers in the region. The ACC System complements our other Permian Basin assets and enhances the services available to the producers in the Northern Delaware Basin. The following table reflects the fair value determination (in millions): Identifiable assets acquired and liabilities assumed: Estimated Useful Lives (Years) Recognized amount Property and equipment 3 - 70 $ 299 Intangible assets 20 646 Goodwill N/A 269 Other assets and liabilities, net (including $4 million of cash acquired) N/A 1 $ 1,215 Intangible assets are included in “Other long-term assets, net” on our Consolidated Balance Sheets. The determination of fair value to intangible assets above is comprised of five acreage dedication contracts and associated customer relationships that will be amortized over a remaining weighted average useful life of approximately 20 years . The value assigned to such intangible assets will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed. Amortization expense was approximately $10 million for the period from February 14, 2017 through December 31, 2017, and the future amortization expense is estimated as follows for the next five years (in millions): 2018 $ 25 2019 $ 34 2020 $ 42 2021 $ 48 2022 $ 54 Goodwill is an intangible asset representing the future economic benefits expected to be derived from other assets acquired that are not individually identified and separately recognized. The goodwill arising from the ACC Acquisition, which is tax deductible, represents the anticipated opportunities to generate future cash flows from undedicated acreage and the synergies created between the ACC System and our existing assets. The assets acquired in the ACC Acquisition, as well as the associated goodwill, are primarily included in our Transportation segment. During the year ended December 31, 2017, we incurred approximately $6 million of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of general and administrative expenses in our Consolidated Statements of Operations. Pro forma financial information assuming the ACC Acquisition had occurred as of the beginning of the calendar year prior to the year of acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes. Other Acquisitions In February 2017, we acquired a propane marine terminal for cash consideration of approximately $41 million . The assets acquired are included in our Facilities segment. We did not recognize any goodwill related to this acquisition. On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). We account for our interest in the Advantage Joint Venture under the equity method of accounting. See Note 8 for additional discussion of our equity method investments. 2016 During the year ended December 31, 2016, we completed two acquisitions for aggregate cash consideration of $289 million . These acquisitions included (i) an integrated system of NGL assets in Western Canada for cash consideration of approximately $204 million and (ii) the remaining interest in a Gulf Coast pipeline that was subsequently sold during the year. The assets acquired were primarily included in our Transportation and Facilities segments. We did no t recognize any goodwill related to these acquisitions. 2015 During the year ended December 31, 2015, we completed three acquisitions for aggregate cash consideration of $105 million . These acquisitions included (i) an additional approximate 28% interest in Frontier Aspen LLC, which is accounted for under the equity method of accounting, (ii) a crude oil terminal included in our Facilities segment and (iii) the remaining interest in a pipeline system included in our Transportation segment. We recognized goodwill of $11 million related to these acquisitions. See Note 8 for additional discussion of our equity method investments. Dispositions and Divestitures During the year ended December 31, 2017, we sold certain non-core assets for total proceeds of $1.1 billion , including: • certain of our Bay Area terminal assets located in California; • our Bluewater natural gas storage facility located in Michigan; • certain non-core pipelines in the Rocky Mountain and Bakken regions, including our interest in SLC Pipeline LLC; • non-core pipeline segments primarily located in the Midwestern United States; and • a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma for our net book value. The Bay Area terminal assets and the Bluewater natural gas storage facility were reported in our Facilities segment. The pipeline assets were reported in our Transportation segment. See Note 8 for additional discussion. In the aggregate, including non-cash impairments recognized upon reclassifications to assets held for sale, we recognized a net gain related to pending or completed asset sales of approximately $43 million for the year ended December 31, 2017, which is included in “Depreciation and amortization” on our Consolidated Statement of Operations. Such amount is comprised of gains of $123 million and losses of $80 million . During the year ended December 31, 2016, we sold several non-core assets, including certain of our Gulf Coast pipelines and East Coast refined products terminals. In addition, we sold interests in Cheyenne Pipeline LLC and STACK Pipeline LLC. See Note 8 for additional discussion. In the aggregate, we recognized a net gain of approximately $100 million related to these transactions, which is included in “Depreciation and amortization” on our Consolidated Statement of Operations. Such amount is comprised of gains of $158 million and losses of $58 million , including $15 million of impairment of goodwill that was included in a disposal group classified as held for sale prior to the closing of such transaction. During 2015, we sold various property and equipment and recognized a net loss of $2 million , which is included in “Depreciation and amortization” on our Consolidated Statement of Operations. As of December 31, 2017, we classified approximately $80 million of assets as held for sale on our Consolidated Balance Sheet (in “Other current assets”) primarily related to a definitive agreement to sell non-core property and equipment included in our Facilities segment. We expect the sale to be consummated in the first half of 2018, subject to customary closing conditions, as applicable. As of December 31, 2016, we classified approximately $275 million of assets as held for sale on our Consolidated Balance Sheet (in “Other current assets”) primarily related to a definitive agreement to sell non-core assets, which were property and equipment included in our Facilities segment. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. In accordance with FASB guidance, we test goodwill to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance provides for a quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. In the quantitative test, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then goodwill is impaired by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. We completed our goodwill impairment test as of June 30, 2017 using a qualitative assessment. We determined that it was more likely than not that the fair value of each reporting unit was greater than its respective book value; therefore, additional impairment testing was not necessary at that time and goodwill was not considered impaired. However, due to a deterioration in the performance of the Supply and Logistics reporting unit and a reduction in projected performance of that reporting unit, we performed a quantitative test for the Supply and Logistics reporting unit as of December 31, 2017. Through the quantitative test of the Supply and Logistics reporting unit’s goodwill for potential impairment, we determined that the fair value of that reporting unit was greater than its respective book value; therefore, goodwill was not considered impaired. However, a further deterioration in the performance of the Supply and Logistics reporting unit could result in an impairment of goodwill. We did not perform a quantitative test for our other reporting units as of December 31, 2017 as there were no indicators of possible impairment. We did not recognize any impairments of goodwill during the last three years. Goodwill by segment and changes in goodwill is reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2015 $ 815 $ 1,087 $ 503 $ 2,405 Foreign currency translation adjustments 6 3 1 10 Dispositions and reclassifications to assets held for sale (15 ) (56 ) — (71 ) Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344 Acquisitions 269 — — 269 Foreign currency translation adjustments 16 7 4 27 Dispositions and reclassifications to assets held for sale (21 ) (53 ) — (74 ) Balance at December 31, 2017 $ 1,070 $ 988 $ 508 $ 2,566 |
Investments in Unconsolidated E
Investments in Unconsolidated Entities | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Entities | Investments in Unconsolidated Entities Investments in entities over which we have significant influence but not control are accounted for under the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on our Consolidated Balance Sheets. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature. Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at December 31, 2017 December 31, Entity (1) Type of Operation 2017 2016 Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) Crude Oil Pipeline 50% $ 69 $ — BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 50% 1,093 1,098 Butte Pipe Line Company Crude Oil Pipeline N/A — 11 Caddo Pipeline LLC Crude Oil Pipeline 50% 67 65 Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 29 30 Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 467 143 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 378 372 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock (2) 50% 75 53 Frontier Aspen LLC Crude Oil Pipeline N/A — 45 Midway Pipeline LLC Crude Oil Pipeline 50% 20 — Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 217 213 Settoon Towing, LLC Barge Transportation Services 50% 69 87 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 73 14 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 199 212 Total Investments in Unconsolidated Entities $ 2,756 $ 2,343 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) Asset is currently under construction by the entity and has not yet been placed in service. On April 3, 2017, we and an affiliate of Noble completed the acquisition of Advantage Pipeline, L.L.C. for a purchase price of $133 million through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our 50% share ( $66.5 million ), we contributed approximately 1.3 million common units with a value of approximately $40 million and approximately $26 million in cash. Through the acquisition, the Advantage Joint Venture owns a 70 -mile, 16 -inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”), which is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Noble serves as operator of the Advantage Pipeline. We account for our interest in the Advantage Joint Venture under the equity method of accounting. During the fourth quarter of 2017, we sold certain of our non-core pipelines in the Rocky Mountain region which included our ownership interests in Butte Pipe Line Company and Frontier Aspen LLC. Additionally, we and an affiliate of CVR Refining, LP (“CVR Refining”) formed a 50/50 joint venture, Midway Pipeline LLC, which acquired from us the Cushing to Broome crude oil pipeline system. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas refinery to the Cushing, Oklahoma oil hub. We will continue to serve as operator of the pipeline. We account for our interest in Midway Pipeline LLC under the equity method of accounting. In June 2016, we sold 50% of our investment in Cheyenne, and in August 2016 we sold 50% of our investment in STACK. As a result of these transactions, we now account for our remaining 50% equity interest in such entities under the equity method of accounting. See Note 6 for additional information related to certain of these transactions. Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. During the year ended December 31, 2017, we received $ 21 million as a return of investment from Settoon Towing, LLC related to the sale of certain of its marine assets. We generally fund our portion of development, construction or capital expansion projects of our equity method investees through capital contributions. Our contributions to these entities increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. During the years ended December 31, 2017 , 2016 and 2015 , we made cash contributions of $398 million , $288 million and $245 million , respectively, to certain of our equity method investees. The contributions for 2017 and 2015 are net of $6 million and $53 million , respectively, of returns of cash contributions made during the periods. In addition, we capitalized interest of $18 million , $13 million and $8 million during the years ended December 31, 2017 , 2016 and 2015 , respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions to Eagle Ford Terminals, Eagle Ford Pipeline, BridgeTex, Diamond and STACK in 2018 related to ongoing projects by such entities. Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $736 million and $758 million at December 31, 2017 and 2016 , respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The basis difference at both December 31, 2017 and 2016 is primarily related to our acquisition of an interest in BridgeTex in 2014. Summarized Financial Information of Unconsolidated Entities Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests. December 31, 2017 2016 Current assets $ 311 $ 303 Noncurrent assets $ 4,162 $ 3,558 Current liabilities $ 129 $ 241 Noncurrent liabilities $ 41 $ 162 Year Ended December 31, 2017 2016 2015 Revenues $ 938 $ 802 $ 769 Operating income $ 650 $ 469 $ 441 Net income $ 640 $ 452 $ 424 |
Other Long-Term Assets, Net
Other Long-Term Assets, Net | 12 Months Ended |
Dec. 31, 2017 | |
Other Assets [Abstract] | |
Other Long-Term Assets, Net | Other Long-Term Assets, Net Other long-term assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2017 2016 Intangible assets (1) $ 1,265 $ 603 Other 60 48 1,325 651 Accumulated amortization (421 ) (361 ) $ 904 $ 290 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 5 for a discussion of property and equipment. The increase in intangible assets for the year ended December 31, 2017 was primarily due to acreage dedication contracts and associated customer relationships associated with our ACC Acquisition. See Note 6 for additional information. Amortization expense for finite-lived intangible assets for the years ended December 31, 2017 , 2016 and 2015 was $54 million , $44 million and $49 million , respectively. Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. We did not recognize any impairments of finite-lived intangible assets during the three years ended December 31, 2017. Our intangible assets that have finite lives consisted of the following (in millions): December 31, 2017 December 31, 2016 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 20 $ 1,188 $ (383 ) $ 805 $ 529 $ (330 ) $ 199 Property tax abatement 7 – 13 38 (30 ) 8 38 (26 ) 12 Other agreements 25 – 70 39 (8 ) 31 36 (5 ) 31 $ 1,265 $ (421 ) $ 844 $ 603 $ (361 ) $ 242 We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions): 2018 $ 63 2019 $ 68 2020 $ 74 2021 $ 75 2022 $ 76 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Debt Debt consisted of the following (in millions): December 31, December 31, SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively (1) $ — $ 563 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.6% and 1.8%, respectively (1) 664 750 Senior notes: 6.13% senior notes due January 2017 — 400 Other 73 2 Total short-term debt (2) 737 1,715 LONG-TERM DEBT Senior notes: 6.50% senior notes due May 2018 (3) — 600 8.75% senior notes due May 2019 (3) — 350 2.60% senior notes due December 2019 500 500 5.75% senior notes due January 2020 500 500 5.00% senior notes due February 2021 600 600 3.65% senior notes due June 2022 750 750 2.85% senior notes due January 2023 400 400 3.85% senior notes due October 2023 700 700 3.60% senior notes due November 2024 750 750 4.65% senior notes due October 2025 1,000 1,000 4.50% senior notes due December 2026 750 750 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 500 500 4.30% senior notes due January 2043 350 350 4.70% senior notes due June 2044 700 700 4.90% senior notes due February 2045 650 650 Unamortized discounts and debt issuance costs (67 ) (76 ) Senior notes, net of unamortized discounts and debt issuance costs 8,933 9,874 Other long-term debt: Commercial paper notes and senior secured hedged inventory facility borrowings (4) 247 247 Other 3 3 Total long-term debt 9,183 10,124 Total debt (5) $ 9,920 $ 11,839 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2017 and 2016 , as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) As of December 31, 2017 and 2016 , balance includes borrowings of $212 million and $410 million , respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) In December 2017, we redeemed our $600 million , 6.50% senior notes due May 2018 and our $350 million , 8.75% senior notes due May 2019. See the “Senior Notes—Senior Note Repayments and Redemptions” section below for further discussion. (4) As of December 31, 2017 and 2016 , we classified a portion of our commercial paper notes and senior secured hedged inventory facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis. (5) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.0 billion and $10.3 billion as of December 31, 2017 and 2016 , respectively. We estimated the aggregate fair value of these notes as of December 31, 2017 and 2016 to be approximately $9.1 billion and $10.4 billion , respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Commercial Paper Program We have a commercial paper program under which we may issue (and have outstanding at any time) up to $3.0 billion in the aggregate of privately placed, unsecured commercial paper notes. Such notes are backstopped by our senior unsecured revolving credit facility and our senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities. Credit Facilities Senior secured hedged inventory facility . We have a credit agreement that provides for a senior secured hedged inventory facility with a committed borrowing capacity of $1.4 billion , of which $400 million is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments, the committed capacity of the facility may be increased to $1.9 billion . Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits. Such obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and are repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one -year extensions, subject to applicable approval. In August 2017, we amended this agreement to, among other things, extend the maturity date of the facility to August 2020 for each extending lender. The maturity date with respect to each non-extending lender (which represent aggregate commitments of approximately $60 million out of total commitments of $1.4 billion from all lenders) remains August 2019. Senior unsecured revolving credit facility. We have a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $1.6 billion . Subject to obtaining additional or increased lender commitments, the committed capacity may be increased to $2.1 billion . The credit agreement also provides for the issuance of letters of credit. Borrowings accrue interest based, at our election, on the Eurocurrency Rate, the Base Rate or the Canadian Prime Rate, in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one -year extensions, subject to applicable approval. In August 2017, we amended this agreement to, among other things, extend the maturity date of the facility to August 2022 for each extending lender. The maturity dates with respect to each non-extending lender (which represent aggregate commitments of $120 million out of total commitments of $1.6 billion from all lenders) remain August 2021 or mature one year earlier. Senior unsecured 364-day revolving credit facility. We have a credit agreement that provides for a 364 -day senior unsecured revolving credit facility with a borrowing capacity of $1.0 billion . In August 2017, we amended this agreement to extend the maturity date to August 2018. Additionally, a provision was added whereby we may elect to have the entire principal balance of any loans outstanding on the maturity date converted to a non-revolving term loan with a maturity date of August 2019. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time. AAP senior secured credit agreement . In connection with the Simplification Transactions, on November 15, 2016, we assumed all of AAP’s then outstanding borrowings under the AAP senior secured credit agreement, and immediately repaid such amounts and canceled the credit agreement. See Note 1 for further discussion of the Simplification Transactions. Senior Notes Our senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100% -owned consolidated finance subsidiary (neither of which have independent assets or operations) and are unsecured senior obligations of such entities and rank equally in right of payment with existing and future senior indebtedness of the issuers. We may, at our option, redeem any series of senior notes at any time in whole or from time to time in part, prior to maturity, at the redemption prices described in the indentures governing the senior notes. Our senior notes are not guaranteed by any of our subsidiaries. Senior Notes Issuances The table below summarizes our issuances of senior unsecured notes during 2016 and 2015 (in millions): Year Description Maturity Face Value Interest Payment Dates 2016 4.50% Senior Notes issued at 99.716% of face value December 2026 $ 750 June 15 and December 15 2015 4.65% Senior Notes issued at 99.846% of face value October 2025 $ 1,000 April 15 and October 15 We did not issue any senior unsecured notes during the year ended December 31, 2017. Senior Note Repayments and Redemptions Our $400 million , 6.13% senior notes matured and were repaid in January 2017. In December 2017, we redeemed our $600 million , 6.50% senior notes due May 2018 and our $350 million , 8.75% senior notes due May 2019. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes. In conjunction with the early redemptions, we recognized a loss of approximately $40 million , recorded to Other income/(expense), net in our Consolidated Statements of Operations. Our $175 million , 5.88% senior notes matured and were repaid in August 2016. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes. Our $150 million , 5.25% senior notes and $400 million , 3.95% senior notes matured and were repaid in June 2015 and September 2015, respectively. We utilized cash on hand and available capacity under our commercial paper program to repay these notes. Maturities The weighted average maturity of our long-term debt outstanding at December 31, 2017 was approximately 12 years . The following table presents the aggregate contractually scheduled maturities of such long-term debt for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2018 $ 247 2019 500 2020 500 2021 600 2022 750 Thereafter 6,653 Covenants and Compliance Our credit agreements (which impact our ability to access our commercial paper program because they provide a financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. Our credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things: • grant liens on certain property; • incur indebtedness, including capital leases; • sell substantially all of our assets or enter into a merger or consolidation; • engage in certain transactions with affiliates; and • enter into certain burdensome agreements. The credit agreements for our senior unsecured revolving credit facility, senior secured hedged inventory facility and senior unsecured 364-day revolving credit facility treat a change of control as an event of default and also require us to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, will not be greater than 5.00 to 1.00 (or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $150 million ), and/or during the GP Simplification Period (the period beginning on November 15, 2016 and ending on December 31, 2017)). For covenant compliance purposes, Consolidated EBITDA may include certain adjustments, including those for material projects and certain non-recurring expenses. Additionally, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio. A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2017 , we were in compliance with the covenants contained in our credit agreements and indentures. Borrowings and Repayments Total borrowings under our credit agreements and commercial paper program for the years ended December 31, 2017 , 2016 and 2015 were approximately $60.8 billion , $60.3 billion and $62.2 billion , respectively. Total repayments under our credit agreements and commercial paper program were approximately $61.5 billion , $61.0 billion and $61.3 billion for the years ended December 31, 2017 , 2016 and 2015 , respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. These letters of credit are issued under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil, NGL or natural gas is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At December 31, 2017 and 2016 , we had outstanding letters of credit of $166 million and $73 million , respectively. Debt Issuance Costs Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. |
Partners' Capital and Distribut
Partners' Capital and Distributions | 12 Months Ended |
Dec. 31, 2017 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Units Outstanding At December 31, 2017 , partners’ capital consisted of outstanding common units and Series A and Series B preferred units, which represent limited partner interests in us, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges as outlined in our partnership agreement. Our general partner has a non-economic interest in us. However, prior to the closing of the Simplification Transactions, our outstanding common units and Series A preferred units represented a 98% effective aggregate ownership interest in us and our subsidiaries after giving effect to the 2% general partner interest. See Note 1 for discussion of the Simplification Transactions. The following table presents the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Common Units Outstanding at December 31, 2014 — — 375,107,793 Sales of common units — — 22,133,904 Issuances of common units under LTIP — — 485,927 Outstanding at December 31, 2015 — — 397,727,624 Sale of Series A preferred units 61,030,127 — — Issuances of Series A preferred units in connection with in-kind distributions 3,358,726 — — Sales of common units — — 26,278,288 Issuances of common units under LTIP — — 480,581 Issuance of common units in connection with Simplification Transactions (Note 1) — — 244,707,926 Outstanding at December 31, 2016 64,388,853 — 669,194,419 Issuances of Series A preferred units in connection with in-kind distributions 5,307,689 — — Sale of Series B preferred units — 800,000 — Sales of common units — — 54,119,893 Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 6) — — 1,252,269 Issuances of common units under LTIP — — 622,557 Outstanding at December 31, 2017 69,696,542 800,000 725,189,138 Equity Offerings Common Unit Issuances . We have entered into several equity distribution agreements under our Continuous Offering Program, pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests. We may also sell common units through overnight or underwritten offerings. In addition, we may sell common units to AAP pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the November 2016 Simplification Transactions. The following table summarizes our sales of common units (net proceeds in millions): Year Type of Offering Common Units Issued Net Proceeds (1) (2) 2017 Continuous Offering Program 4,033,567 $ 129 (3) 2017 Omnibus Agreement (4) 50,086,326 (5) 1,535 2017 Total 54,119,893 $ 1,664 2016 Total Continuous Offering Program 26,278,288 $ 805 (3) 2015 Continuous Offering Program 1,133,904 $ 59 (3) 2015 Underwritten Offering 21,000,000 1,062 2015 Total 22,133,904 $ 1,121 (1) Amounts are net of costs associated with the offerings. (2) For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of $9 million and $22 million during 2016 and 2015 , respectively. (3) We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid $1 million , $8 million and $1 million of such commissions during 2017 , 2016 and 2015 , respectively. (4) Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, PAGP used the net proceeds from the sale of PAGP Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of PAGP Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to purchase from us an equivalent number of our common units. (5) Includes (i) approximately 1.8 million common units issued to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and (ii) 48.3 million common units issued to AAP in connection with PAGP’s March 2017 underwritten offering. Series A Preferred Unit Issuance . On January 28, 2016 (the “Issuance Date”), we completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in us for a cash purchase price of $26.25 per unit (the “Issue Price”), resulting in total net proceeds to us, after deducting offering expenses and the 2% transaction fee due to the purchasers and including our general partner’s proportionate capital contribution, of approximately $1.6 billion . Certain of the purchasers or their affiliates are related parties. See Note 15 for additional information. The Series A preferred units rank pari passu with our Series B preferred units, and senior to our common units and to each other class or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units receive cumulative quarterly distributions, subject to customary antidilution adjustments, equal to $0.525 per unit ( $2.10 per unit annualized). With respect to each quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we elected to pay distributions on the Series A preferred units in additional Series A preferred units. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash. The purchasers may convert their Series A preferred units into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter). We may convert the Series A preferred units into common units at any time (but not more often than once per quarter) after the third anniversary of the Issuance Date (January 28, 2019), in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150% of the Issue Price for the preceding 20 trading days. The Series A preferred units vote on an as-converted basis with our common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units to common units at the then applicable conversion rate. For a period of 30 days following (a) the fifth anniversary of the Issuance Date of the Series A preferred units and (b) each subsequent anniversary of the Issuance Date, the holders of the Series A preferred units, acting by majority vote, may make a one -time election to reset the distribution rate to equal the then applicable rate of the ten-year U.S. Treasury plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 12 for additional information. If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the Issuance Date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95% of the volume-weighted average price of the common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions. Series B Preferred Unit Issuance. On October 10, 2017, we issued 800,000 Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series B preferred units”) at a price to the public of $1,000 per unit. We used the net proceeds of $788 million , after deducting the underwriters’ discounts and offering expenses, from the issuance of the Series B preferred units to repay amounts outstanding under our credit facilities and commercial paper program and for general partnership purposes. The Series B preferred units represent perpetual equity interests in us, and they have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to our common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, on par with our outstanding Series A preferred units. The Series B preferred units have a liquidation preference of $1,000 per unit. Holders of our Series B preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative semiannual or quarterly cash distributions, as applicable. Distributions on the Series B preferred units accrue and are cumulative from October 10, 2017, the date of original issue, and are payable semiannually in arrears on the 15th day of May and November through and including November 15, 2022, and after November 15, 2022, quarterly in arrears on the 15th day of February, May, August and November of each year. The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 is 6.125% per year of the liquidation preference per unit (equal to $61.25 per unit per year). On and after November 15, 2022, distributions on the Series B preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.11% . Upon the occurrence of certain rating agency events, we may redeem the Series B preferred units, in whole but not in part, at a price of $1,020 ( 102% of the liquidation preference) per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. In addition, at any time on or after November 15, 2022, we may redeem the Series B preferred units, at our option, in whole or in part, at a redemption price of $1,000 per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. Distributions In accordance with our partnership agreement, after making distributions to holders of outstanding preferred units, we distribute 100% of our available cash within 45 days following the end of each quarter to common unitholders of record. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established in the reasonable discretion of our general partner for future requirements. The following table details distributions paid to common unitholders (and, prior to the Simplification Transactions, our general partner) during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP (1) Total 2017 $ 849 $ 537 $ 1,386 $ 1.95 2016 $ 1,062 $ 565 $ 1,627 $ 2.65 2015 $ 1,081 $ 590 $ 1,671 $ 2.76 (1) Prior to the Simplification Transactions, our general partner was entitled to receive (i) distributions with respect to its 2% indirect general partner interest and (ii) as the holder of our IDRs, incentive distributions if the amount we distributed with respect to any quarter exceeded certain specified levels. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. During the year ended December 31, 2017, AAP received distributions on the common units it owned. On January 8, 2018, we declared a cash distribution of $0.30 per unit on our outstanding common units. The total distribution of $218 million was paid on February 14, 2018 to unitholders of record on January 31, 2018, for the period October 1, 2017 through December 31, 2017. Of this amount, approximately $85 million was paid to AAP. Series A Preferred Unit Distributions. In 2017, we issued 5,307,689 Series A preferred units in lieu of cash distributions of $139 million . In 2016, we issued 3,358,726 Series A preferred units in lieu of cash distributions of $89 million . On February 14, 2018, we issued 1,393,926 Series A preferred units in lieu of a cash distribution of $37 million . Since the February 14, 2018 Series A preferred unit distribution was declared as payment-in-kind, the distribution payable was accrued to partners’ capital as of December 31, 2017 and thus had no net impact on the Series A preferred unitholders’ capital account. Series B Preferred Unit Distributions. We paid a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holders of record at the close of business on November 1, 2017 in an amount equal to approximately $5.9549 per unit (a total distribution of approximately $5 million ). At December 31, 2017, we had accrued approximately $6 million of distributions payable to our Series B preferred unitholders. Income Allocation We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Following the closing of the Simplification Transactions, net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders. In accordance with our partnership agreement, our Series A preferred unitholders are not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For periods prior to the Simplification Transactions, our general partner and common unitholders were allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner for distributions declared and paid following the close of each quarter and (ii) cash distributions to our Series A preferred unitholders. Our Series A preferred unitholders were not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for distributions attributable to the period (whether paid in cash or in-kind) on our Series A and Series B preferred units. See Note 3 for additional information. Noncontrolling Interests in Subsidiaries During the fourth quarter of 2017, we sold SLC Pipeline LLC, in which we previously owned a 75% interest and had consolidated under GAAP. As a result of this sale, the noncontrolling interest of 25% was derecognized. We did not have any noncontrolling interests in subsidiaries at December 31, 2017 . See Note 6 for additional information regarding the sale of SLC Pipeline LLC. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives and Risk Management Activities | Derivatives and Risk Management Activities We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Commodity Price Risk Hedging Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories: Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of December 31, 2017 , net derivative positions related to these activities included: • A net long position of 3.3 million barrels associated with our crude oil purchases, which was unwound ratably during January 2018 to match monthly average pricing. • A net short time spread position of 5.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through February 2019. • A crude oil grade basis position of 30.3 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials. • A net short position of 16.5 million barrels through December 2020 related to anticipated net sales of our crude oil and NGL inventory. Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2017 , our PLA hedges included a net short position consisting of crude oil futures of 1.1 million barrels and a long call option position of 0.9 million barrels through December 2019. Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of December 31, 2017 , we had a long natural gas position of 54.3 Bcf which hedges our natural gas processing and operational needs through December 2020. We also had a short propane position of 8.6 million barrels through December 2018, a short butane position of 2.6 million barrels through December 2018 and a short WTI position of 1.0 million barrels through December 2018. In addition, we had a long power position of 0.4 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2019. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate associated interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2017 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 16 forward starting swaps (30-year) $ 400 6/15/2018 2.86 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards. As of December 31, 2017 , our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales. The following table summarizes our open forward exchange contracts as of December 31, 2017 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2018 $ 87 $ 109 $1.00 - $1.26 Forward exchange contracts that exchange USD for CAD: 2018 $ 645 $ 816 $1.00 - $1.27 Preferred Distribution Rate Reset Option A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheet. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Consolidated Statement of Operations. At December 31, 2017 and 2016 , the fair value of this embedded derivative was a liability of approximately $22 million and $32 million , respectively. We recognized gains of approximately $13 million and $30 million for the years ended December 31, 2017 and 2016 , respectively. See Note 11 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option. Summary of Financial Impact We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows. A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Year Ended December 31, 2017 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (188 ) $ (188 ) Field operating costs — (10 ) (10 ) Depreciation and amortization (3 ) — (3 ) Interest Rate Derivatives Interest expense, net (18 ) — (18 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 8 8 Preferred Distribution Rate Reset Option Other income/(expense), net — 13 13 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (21 ) $ (177 ) $ (198 ) Year Ended December 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 2 $ (344 ) $ (342 ) Transportation segment revenues — 5 5 Interest Rate Derivatives Interest expense, net (14 ) — (14 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (3 ) (3 ) Preferred Distribution Rate Reset Option Other income/(expense), net — 30 30 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (12 ) $ (312 ) $ (324 ) Year Ended December 31, 2015 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 56 $ 152 $ 208 Transportation segment revenues — 8 8 Field operating costs — (18 ) (18 ) Interest Rate Derivatives Interest expense, net (11 ) — (11 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (31 ) (31 ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ 45 $ 111 $ 156 (1) During the year ended December 31, 2017, we reclassified losses of approximately $10 million to Interest expense, net. During the year ended December 31, 2016, we reclassified losses of approximately $2 million to Supply and Logistics segment revenues and $2 million to Interest expense, net. During the year ended December 31, 2015, we reclassified a loss of approximately $4 million to Interest expense, net. Each reclassification from AOCI to earnings was due to anticipated hedged transactions being probable of not occurring. (2) Amounts in Interest expense, net include a loss of $4 million during the year ended December 31, 2016 attributable to the ineffective portion of cash flow hedges. No ineffectiveness was recognized for cash flow hedges during the years ended December 31, 2017 or 2015. The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Interest rate derivatives Other current liabilities $ 2 Other current liabilities $ (27 ) Other long-term liabilities and deferred credits (11 ) Total derivatives designated as hedging instruments $ 2 $ (38 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 73 Other current assets $ (227 ) Other long-term assets, net 1 Other current liabilities (131 ) Other current liabilities 5 Other long-term liabilities and deferred credits (5 ) Other long-term liabilities and deferred credits 3 Foreign currency derivatives Other current assets 6 Other current assets (2 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (22 ) Total derivatives not designated as hedging instruments $ 88 $ (387 ) Total derivatives $ 90 $ (425 ) The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Interest rate derivatives $ — Other current liabilities $ (23 ) Other long-term liabilities and deferred credits (27 ) Total derivatives designated as hedging instruments $ — $ (50 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 101 Other current assets $ (344 ) Other long-term assets, net 2 Other long-term assets, net (1 ) Other long-term liabilities and deferred credits 2 Other current liabilities (14 ) Other long-term liabilities and deferred credits (34 ) Foreign currency derivatives Other current liabilities 3 Other current liabilities (6 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (32 ) Total derivatives not designated as hedging instruments $ 108 $ (431 ) Total derivatives $ 108 $ (481 ) Our derivative transactions (other than the Preferred Distribution Rate Reset Option) are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties. Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable/(payable): December 31, 2017 December 31, 2016 Initial margin $ 48 $ 119 Variation margin posted 164 291 Net broker receivable $ 212 $ 410 The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): December 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 90 $ (425 ) $ 108 $ (481 ) Netting adjustment (239 ) 239 (350 ) 350 Cash collateral paid 212 — 410 — Net position - asset/(liability) $ 63 $ (186 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 167 $ — Other long-term assets, net 1 — 1 — Other current liabilities — (151 ) — (40 ) Other long-term liabilities and deferred credits — (35 ) — (91 ) $ 63 $ (186 ) $ 168 $ (131 ) As of December 31, 2017 , there was a net loss of $223 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at December 31, 2017 , we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The remaining deferred loss of $215 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of December 31, 2017 ; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions): Year Ended December 31, 2017 2016 2015 Commodity derivatives, net $ — $ — $ 33 Interest rate derivatives, net (16 ) (33 ) (32 ) Total $ (16 ) $ (33 ) $ 1 At December 31, 2017 and December 31, 2016 , none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us. Recurring Fair Value Measurements Derivative Financial Assets and Liabilities The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions): Fair Value as of December 31, 2017 Fair Value as of December 31, 2016 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 5 $ (278 ) $ (8 ) $ (281 ) $ (113 ) $ (171 ) $ (4 ) $ (288 ) Interest rate derivatives — (36 ) — (36 ) — (50 ) — (50 ) Foreign currency derivatives — 4 — 4 — (3 ) — (3 ) Preferred Distribution Rate Reset Option — — (22 ) (22 ) — — (32 ) (32 ) Total net derivative asset/(liability) $ 5 $ (310 ) $ (30 ) $ (335 ) $ (113 ) $ (224 ) $ (36 ) $ (373 ) (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. Level 1 Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets. Level 2 Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity contracts and the Preferred Distribution Rate Reset Option contained in our partnership agreement which is classified as an embedded derivative. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing timing estimates, which involve management judgment. Significant changes in timing could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Consolidated Statements of Operations as Supply and Logistics segment revenues. The fair value of the embedded derivative feature contained in our partnership agreement is based on a valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our common unit price, ten-year U.S. treasury rates, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Consolidated Statements of Operations as “Other income/(expense), net.” To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur. Rollforward of Level 3 Net Asset/(Liability) The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions): Year Ended December 31, 2017 2016 Beginning Balance $ (36 ) $ 11 Net gains for the period included in earnings 12 28 Settlements 4 (10 ) Derivatives entered into during the period (10 ) (65 ) Ending Balance $ (30 ) $ (36 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ 5 $ (36 ) |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions. Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2017 and 2016 , we had not recognized any material amounts in connection with uncertainty in income taxes. U.S. Federal and State Taxes As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2017 , 2016 , and 2015 was immaterial. Canadian Federal and Provincial Taxes All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S. income tax purposes) and that are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense. Tax Components Components of income tax expense are as follows (in millions): Year Ended December 31, 2017 2016 2015 Current income tax expense: State income tax $ 1 $ 2 $ 1 Canadian federal and provincial income tax 27 83 83 Total current income tax expense $ 28 $ 85 $ 84 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ 16 $ (60 ) $ 16 Total deferred income tax expense/(benefit) $ 16 $ (60 ) $ 16 Total income tax expense $ 44 $ 25 $ 100 The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions): Year Ended December 31, 2017 2016 2015 Income before tax $ 902 $ 755 $ 1,006 Partnership earnings not subject to current Canadian tax (756 ) (723 ) (773 ) $ 146 $ 32 $ 233 Canadian federal and provincial corporate tax rate 27 % 27 % 26 % Income tax at statutory rate $ 39 $ 8 $ 61 Canadian withholding tax $ 2 $ 13 $ 14 Canadian permanent differences and rate changes 2 2 24 State income tax 1 2 1 Total income tax expense $ 44 $ 25 $ 100 Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2017 2016 Deferred tax assets: Derivative instruments $ 74 $ 49 Book accruals in excess of current tax deductions 22 24 Net operating losses 3 4 Total deferred tax assets 99 77 Deferred tax liabilities: Property and equipment in excess of tax values (455 ) (394 ) Other (50 ) (41 ) Total deferred tax liabilities (505 ) (435 ) Net deferred tax liabilities $ (406 ) $ (358 ) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 3 $ 4 Other long-term liabilities and deferred credits (409 ) (362 ) $ (406 ) $ (358 ) As of December 31, 2017 , we had foreign net operating loss carryforwards of $9 million , which will expire beginning in 2034. Generally, tax returns for our Canadian entities are open to audit from 2008 through 2017. Our U.S. and state tax years are generally open to examination from 2014 to 2017. |
Major Customers and Concentrati
Major Customers and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2017 | |
Risks and Uncertainties [Abstract] | |
Major Customers and Concentration of Credit Risk | Major Customers and Concentration of Credit Risk Marathon Petroleum Corporation and its subsidiaries accounted for 19% , 18% and 17% of our revenues for the years ended December 31, 2017 , 2016 and 2015 , respectively. ExxonMobil Corporation and its subsidiaries accounted for 11% , 14% and 13% of our revenues for the years ended December 31, 2017 , 2016 and 2015 , respectively. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues in each of the years ended December 31, 2017 and 2016. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2017 . The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins. Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 2 for additional discussion of our accounts receivable and our review of credit exposure. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Ownership of PAGP Class C Shares As of December 31, 2017 and 2016 , we owned 510,925,432 and 491,910,863 , respectively, Class C shares of PAGP. The Class C shares represent a non-economic limited partner interest in PAGP that provides us, as the sole holder, a “pass-through” voting right through which our common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors, commencing in May 2018. Reimbursement of Our General Partner and its Affiliates Our general partner provides general and administrative services necessary to manage and operate our business, properties and assets, including employing or retaining personnel. We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2017 , 2016 and 2015 were $489 million , $514 million and $648 million , respectively. Omnibus Agreement In connection with the Simplification Transactions completed in November 2016, the Plains Entities entered into an Omnibus Agreement, which provides for the following: • that, for all periods following the closing of the Simplification Transactions, we will pay all direct or indirect expenses of any of the PAGP Entities, other than income taxes (including, but not limited to, (i) compensation for the directors of PAGP GP, (ii) director and officer liability insurance, (iii) listing exchange fees, (iv) investor relations expenses and (v) fees related to legal, tax, financial advisory and accounting services). We paid $4 million of such expenses in both 2017 and 2016; • the ability of PAGP to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of our common units from us. During the year ended December 31, 2017, we issued approximately 1.8 million common units to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and 48.3 million common units to AAP in connection with PAGP’s March 2017 underwritten offering (See Note 11 for additional information); and • the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding ability to lend such proceeds to us, in each case on substantially the same terms as incurred by PAGP. See Note 1 for discussion of the Simplification Transactions. Transactions with Oxy As of December 31, 2017 , Oxy had a representative on the board of directors of PAGP GP and owned approximately 11% of the limited partner interests in AAP. During the three years ended December 31, 2017 , we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Consolidated Statements of Operations from those transactions is included below (in millions): Year Ended December 31, 2017 2016 2015 Revenues $ 920 $ 655 $ 866 Purchases and related costs (1) $ (253 ) $ 42 $ 41 (1) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): December 31, 2017 2016 Trade accounts receivable and other receivables $ 1,075 $ 789 Accounts payable $ 990 $ 836 Transactions with Equity Method Investees We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting (see Note 8 for information related to these investments). We recorded revenues of $3 million , $14 million and $17 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. During the three years ended December 31, 2017 , we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services totaled $434 million , $209 million and $164 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market. Receivables from our equity method investees totaled $26 million and $39 million at December 31, 2017 and 2016 , respectively, and primarily included amounts related to transportation services. In addition, at December 31, 2016, we had prepaid tariff costs related to our equity method investees of $14 million . Accounts payable to our equity method investees were $41 million and $35 million at December 31, 2017 and 2016 , respectively, and primarily included amounts related to transportation services. In addition, we have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Series A Preferred Unit Issuance In January 2016, we completed a private placement of Series A preferred units. Certain of the purchasers of the Series A preferred units or their affiliates are related parties. Kayne Anderson Capital Advisors, L.P. and certain of its affiliates and an affiliate of The Energy Minerals Group hold ownership interests in our general partner. In addition, certain of the current directors of our general partner are affiliated with certain of the purchasers. See Note 11 for additional information about our Series A preferred units. |
Equity-Indexed Compensation Pla
Equity-Indexed Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Indexed Compensation Plans | Equity-Indexed Compensation Plans PAA Long-Term Incentive Plan Awards Our LTIP awards include both liability-classified and equity-classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of liability-classified LTIP awards is calculated based on the closing market price of the underlying PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value of equity-classified LTIP awards is calculated based on the closing market price of the underlying PAA unit on the respective grant dates and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipient. This fair value is recognized as compensation expense over the service period. Certain LTIP awards contain performance conditions based on the attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would be if we had been accruing for these awards since the grant date. The following is a summary of the awards authorized under our LTIPs as of December 31, 2017 (in millions): LTIP PAA LTIP Awards Authorized Plains All American 2013 Long-Term Incentive Plan 13.1 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 10.8 Total 25.2 Although other types of awards are contemplated under certain of the LTIPs, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting, and “tracking units,” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a PAA common unit at the time of vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. As of December 31, 2017, 7.3 million LTIP awards were outstanding. Of this amount, 2.6 million include DERs. The outstanding and probable LTIP awards are expected to vest at various dates between January 1, 2018 and December 31, 2022. Our accrued liability at December 31, 2017 related to all outstanding liability-classified LTIP awards and DERs was $27 million , of which $15 million was classified as short-term and $12 million was classified as long-term. These short- and long-term accrued LTIP liabilities are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. At December 31, 2016 , the accrued liability was $38 million , of which $25 million was classified as short-term and $13 million was classified as long-term. Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): PAA Units (1) Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 7.3 $ 41.45 Granted 2.1 $ 28.76 Vested (2.1 ) $ 28.91 Cancelled or forfeited (0.4 ) $ 44.56 Outstanding at December 31, 2015 6.9 $ 41.23 Granted 4.5 $ 23.38 Vested (1.9 ) $ 45.91 Modified — $ (8.21 ) Cancelled or forfeited (0.6 ) $ 37.19 Outstanding at December 31, 2016 8.9 $ 29.62 Granted 0.9 $ 23.52 Vested (1.7 ) $ 42.12 Modified — $ (6.04 ) Cancelled or forfeited (0.8 ) $ 26.99 Outstanding at December 31, 2017 7.3 $ 24.68 (1) Approximately 0.6 million , 0.5 million and 0.5 million PAA common units were issued, net of tax withholding of approximately 0.2 million , 0.3 million and 0.3 million units during 2017 , 2016 and 2015 , respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 0.9 million , 1.1 million and 1.3 million units) that vested during 2017 , 2016 and 2015 , respectively, were settled in cash. AAP Management Units In August 2007, the owners of AAP authorized the issuance of AAP Management Units (a profits interest) to provide additional long-term incentives and encourage retention for certain members of our senior management. This plan has been discontinued and there will be no new grants of AAP Management Units; however, as of December 31, 2017, 0.8 million outstanding AAP Management Units were unearned. These AAP Management Units will become earned based on the attainment of certain PAA distribution levels and additional performance conditions based on distributable cash flow measures determined by management. Once earned, we will issue to AAP approximately 0.941 common units for each AAP Management Unit, and each AAP Management Unit will be entitled to a distribution equal to approximately 94.1% of the distribution paid by AAP to an AAP unit on a quarterly basis. Once vested, each AAP Management Unit holder is entitled to convert his or her AAP Management Units into AAP units and a like number of PAGP Class B shares based on a conversion ratio of approximately 0.941 AAP units and Class B shares for each AAP Management Unit. Equity-Indexed Compensation Plan Information We refer to all of the LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions): Year Ended December 31, 2017 2016 2015 Equity-indexed compensation expense $ 41 $ 60 $ 27 LTIP unit-settled vestings $ 16 $ 24 $ 37 LTIP cash-settled vestings $ 25 $ 28 $ 66 Based on the December 31, 2017 fair value measurement and probability assessment regarding future distributions, we expect to recognize $75 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessments regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions): Year Equity-Indexed Compensation Plan Fair Value Amortization (1) 2018 $ 42 2019 21 2020 9 2021 2 2022 1 Total $ 75 (1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2017 . |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Commitments We have commitments, some of which are leases, related to real property, equipment and operating facilities. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees. Future non-cancelable commitments related to these items at December 31, 2017 are summarized below (in millions): 2018 2019 2020 2021 2022 Thereafter Total Leases, rights-of-way easements and other (1) $ 188 $ 155 $ 127 $ 107 $ 90 $ 363 $ 1,030 Other commitments (2) 205 178 145 127 109 299 1,063 Total $ 393 $ 333 $ 272 $ 234 $ 199 $ 662 $ 2,093 (1) Includes operating and capital leases as defined by FASB guidance, as well as obligations for rights-of-way easements. Leases are primarily for (i) railcars, (ii) land and surface rentals, (iii) office buildings, (iv) pipeline assets and (v) vehicles and trailers. We recognize expense on a straight-line basis over the life of the agreement, as applicable. Lease expense for 2017 , 2016 and 2015 was $207 million , $198 million and $164 million , respectively. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $760 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Expense associated with these storage, transportation and throughput agreements was approximately $ 197 million , $ 157 million and $ 85 million for 2017, 2016 and 2015, respectively. Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery. Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed. At December 31, 2017 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $162 million , of which $72 million was classified as short-term and $90 million was classified as long-term. At December 31, 2016 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $147 million , of which $61 million was classified as short-term and $86 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. At December 31, 2017 , we had recorded receivables totaling $55 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $29 million was reflected in “Trade accounts receivable and other receivables, net” and $26 million was reflected in “Other long-term assets, net” on our Consolidated Balance Sheet. At December 31, 2016 , we had recorded $56 million of such receivables, of which $39 million was reflected in “Trade accounts receivable and other receivables, net” and $17 million was reflected in “Other long-term assets, net” on our Consolidated Balance Sheet. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident . In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean. As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending: On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in service under a pressure restriction. No timeline has been established for the restart of Line 901 or Line 903. On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us, in the future. On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. By letter dated September 21, 2017, PHMSA issued a Final Order in this matter withdrawing one alleged violation and affirming a second. With regard to the second violation, PHMSA further determined that compliance had been achieved and included no compliance terms related to it in the Final Order. We therefore consider this matter closed. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of 46 counts. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Since May of 2016, 33 of the criminal charges against PAA (including one felony charge) and all of the criminal charges against our employee, have been dismissed. Seven of the remaining 13 charges are misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining six counts relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges (including the three felony charges) are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA continues to vigorously defend itself against the charges. Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several of our employees and has expressed an interest in talking to other employees; consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil actions or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims for payment as we receive them. In addition, we have also had nine class action lawsuits filed against us, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. To date, the court has certified two sub-classes of claimants and denied certification of the other proposed sub-classes. The sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas, and (ii) individuals or businesses who were employed by or had contracts with certain designated oil platforms and related on shore processing facilities in the vicinity of the release as of the date of the release. We are appealing the oil industry class certification. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages. There have also been two securities law class action lawsuits filed on behalf of certain purported investors in the Partnership and/or PAGP against the Partnership, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of the Partnership’s pipelines and related facilities through false and misleading statements, omission of material facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attribute to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs have refiled their complaint and we are opposing their claims. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with this lawsuit; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters. In addition, four unitholder derivative lawsuits have been filed by certain purported investors in the Partnership against the Partnership, certain of its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court. Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. The other remaining lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs in the remaining lawsuit claim that the Partnership suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in this lawsuit and have responded accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with this lawsuit. We have also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief. In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, as of December 31, 2017 , we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $335 million , which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We accrued such estimate of aggregate total costs to “Field operating costs” in our Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (iv) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident. As of December 31, 2017 , we had a remaining undiscounted gross liability of $94 million related to this event, of which approximately $62 million is presented as a current liability in “Accounts payable and accrued liabilities” on our Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through December 31, 2017 , we had collected, subject to customary reservations, $174 million out of the approximate $220 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of December 31, 2017 , we have recognized a receivable of approximately $47 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately $22 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheet, with the remainder in “Other long-term assets, net”. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. Mesa to Basin Pipeline . On January 6, 2016, PHMSA issued a Notice of Probable Violation and Proposed Civil Penalty relating to an approximate 500 barrel release of crude oil that took place on January 1, 2015 on our Mesa to Basin 12” pipeline in Midland, Texas. PHMSA conducted an accident investigation and reviewed documentation related to the incident, and concluded that we had committed probable violations of certain pipeline safety regulations. In the Notice, PHMSA maintains that we failed to carry out our written damage prevention program and to follow our pipeline excavation/ditching and backfill procedures on four separate occasions, and that such failures resulted in outside force damage that led to the January 1, 2015 release. In early March 2017, PHMSA issued a final order that concluded that we followed our pipeline excavation/ditching and backfill procedures, but maintained that we failed to carry out our written damage prevention program and imposed a civil penalty of $184,300 that was promptly paid. Environmental Remediation We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Insurance Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain various types and varying levels of insurance coverage that we consider adequate under the circumstances to cover our operations and properties, and we self-insure certain risks, including gradual pollution and named windstorm. With respect to our insurance, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows. The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. Additionally we self-insure certain risks including, gradual pollution and named windstorm. With respect to our insurance coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows. |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data (Unaudited) | Quarterly Financial Data (Unaudited) First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) (in millions, except per unit data) 2017 Total revenues $ 6,667 $ 6,078 $ 5,873 $ 7,605 $ 26,223 Gross margin (2) $ 665 $ 325 $ 112 $ 327 $ 1,429 Operating income $ 591 $ 257 $ 44 $ 261 $ 1,153 Net income $ 444 $ 189 $ 34 $ 191 $ 858 Net income attributable to PAA $ 444 $ 188 $ 33 $ 191 $ 856 Basic net income/(loss) per common unit $ 0.59 $ 0.21 $ (0.01 ) $ 0.19 $ 0.96 Diluted net income/(loss) per common unit $ 0.58 $ 0.21 $ (0.01 ) $ 0.19 $ 0.95 Cash distributions per common unit (3) $ 0.55 $ 0.55 $ 0.55 $ 0.30 $ 1.95 2016 Total revenues $ 4,111 $ 4,950 $ 5,170 $ 5,952 $ 20,182 Gross margin (2) $ 349 $ 219 $ 419 $ 286 $ 1,273 Operating income $ 282 $ 146 $ 349 $ 218 $ 994 Net income $ 203 $ 102 $ 298 $ 127 $ 730 Net income attributable to PAA $ 202 $ 101 $ 297 $ 126 $ 726 Basic net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Diluted net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Cash distributions per common unit (3) $ 0.70 $ 0.70 $ 0.70 $ 0.55 $ 2.65 (1) The sum of the four quarters may not equal the total year due to rounding. (2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization. (3) Represents cash distributions declared and paid in the period presented. |
Operating Segments
Operating Segments | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Operating Segments | Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See “Revenue Recognition” in Note 2 for a summary of the types of products and services from which each segment derives its revenues. Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. The measure of segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items including (i) gains or losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in segment adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash”. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. The following tables reflect certain financial data for each segment (in millions): Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2017 Revenues: External customers (1) $ 1,021 $ 555 $ 25,056 $ (409 ) $ 26,223 Intersegment (2) 697 618 9 409 1,733 Total revenues of reportable segments $ 1,718 $ 1,173 $ 25,065 $ — $ 27,956 Equity earnings in unconsolidated entities $ 290 $ — $ — $ 290 Segment adjusted EBITDA $ 1,287 $ 734 $ 60 $ 2,081 Capital expenditures (3) $ 2,126 $ 312 $ 20 $ 2,458 Maintenance capital $ 120 $ 114 $ 13 $ 247 As of December 31, 2017 Total assets $ 12,661 $ 7,313 $ 5,377 $ 25,351 Investments in unconsolidated entities $ 2,681 $ 75 $ — $ 2,756 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2016 Revenues: External customers (1) $ 954 $ 546 $ 19,004 $ (322 ) $ 20,182 Intersegment (2) 630 561 14 322 1,527 Total revenues of reportable segments $ 1,584 $ 1,107 $ 19,018 $ — $ 21,709 Equity earnings in unconsolidated entities $ 195 $ — $ — $ 195 Segment adjusted EBITDA $ 1,141 $ 667 $ 359 $ 2,167 Capital expenditures (3) $ 1,063 $ 577 $ 54 $ 1,694 Maintenance capital $ 121 $ 55 $ 10 $ 186 As of December 31, 2016 Total assets $ 10,917 $ 7,556 $ 5,737 $ 24,210 Investments in unconsolidated entities $ 2,290 $ 53 $ — $ 2,343 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2015 Revenues: External customers (1) $ 953 $ 528 $ 21,927 $ (256 ) $ 23,152 Intersegment (2) 641 522 18 256 1,437 Total revenues of reportable segments $ 1,594 $ 1,050 $ 21,945 $ — $ 24,589 Equity earnings in unconsolidated entities $ 183 $ — $ — $ 183 Segment adjusted EBITDA $ 1,056 $ 588 $ 568 $ 2,212 Capital expenditures (3) $ 1,278 $ 813 $ 184 $ 2,275 Maintenance capital $ 144 $ 68 $ 8 $ 220 As of December 31, 2015 Total assets $ 10,345 $ 7,330 $ 4,613 $ 22,288 Investments in unconsolidated entities $ 1,998 $ 29 $ — $ 2,027 (1) Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM. (2) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. (3) Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities. Segment Adjusted EBITDA Reconciliation The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Year Ended December 31, 2017 2016 2015 Segment adjusted EBITDA $ 2,081 $ 2,167 $ 2,212 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (45 ) (50 ) (45 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 46 (404 ) (110 ) Long-term inventory costing adjustments (4) 24 58 (99 ) Deficiencies under minimum volume commitments, net (5) (2 ) (46 ) — Equity-indexed compensation expense (6) (23 ) (33 ) (27 ) Net gain/(loss) on foreign currency revaluation (7) 26 (9 ) 29 Line 901 incident (8) (32 ) — (83 ) Significant acquisition-related expenses (9) (6 ) — — Depreciation and amortization (626 ) (494 ) (432 ) Interest expense, net (510 ) (467 ) (432 ) Other income/(expense), net (31 ) 33 (7 ) Income before tax 902 755 1,006 Income tax expense (44 ) (25 ) (100 ) Net income 858 730 906 Net income attributable to noncontrolling interests (2 ) (4 ) (3 ) Net income attributable to PAA $ 856 $ 726 $ 903 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization and gains or losses on significant asset sales of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for the year prior to 2016 were not significant to segment adjusted EBITDA ( $13 million for the year ended December 31, 2015). (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 17 for additional information regarding the Line 901 incident. (9) Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the year ended December 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance. Acquisition-related expenses for the 2016 and 2015 periods were not significant to segment adjusted EBITDA. Geographic Data We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions): Year Ended December 31, Revenues (1) 2017 2016 2015 United States $ 21,443 $ 15,599 $ 18,701 Canada 4,780 4,583 4,451 $ 26,223 $ 20,182 $ 23,152 (1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped. December 31, Long-Lived Assets (1) 2017 2016 United States $ 17,167 $ 16,041 Canada 4,179 3,895 $ 21,346 $ 19,936 (1) Excludes long-term derivative assets and long-term deferred tax assets. |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Consolidation and Presentation | Basis of Consolidation and Presentation The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2017 and 2016 , and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2017 , 2016 and 2015 . All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) impairment assessments of goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, (v) equity-indexed compensation plan accruals, (vi) property and equipment, depreciation and amortization expense, asset retirement obligations and impairments, (vii) allowance for doubtful accounts and (viii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates. |
Revenue Recognition | Revenue Recognition Supply and Logistics Segment Revenues. Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges. The sales under these exchanges are netted to zero in Supply and Logistics segment revenues in our Consolidated Statements of Operations. Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting. Transportation Segment Revenues. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff, as well as revenues associated with agreements for committed space on various assets. Tariff revenues are recognized when the service is provided pursuant to specifications outlined in the tariffs. Revenues associated with fees are recognized in the month to which the fee applies. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the allowance volumes and actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) in the month of occurrence. Facilities Segment Revenues. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services and (vi) loading and unloading fees at our rail terminals. We generate revenue through a combination of month-to-month and multi-year agreements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from NGL fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. Minimum Volume Commitments. We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. |
Purchases and Related Costs | Purchases and Related Costs Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for storage and transportation, whether by pipeline, truck, rail, ship or barge and (iii) performance-related bonus costs. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us. Purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations. |
Field Operating Costs and General and Administrative Expenses | Field Operating Costs and General and Administrative Expenses Field operating costs consist of various field operating expenses, including payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; certain information systems and legal costs; office rent; contract and consultant costs; and audit and tax fees. |
Foreign Currency Transactions/Translation | Foreign Currency Transactions/Translation Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheets. Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the Consolidated Statements of Operations. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. |
Accounts Receivable, Net | Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. Prices for crude oil, natural gas and NGLs can fluctuate widely. For example, NYMEX West Texas Intermediate oil prices have been volatile and ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Although prices recovered somewhat in 2017 to close the year at $60.42 per barrel, the sustained decrease in commodity prices since late 2014 has caused liquidity and leverage issues throughout the energy industry, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of December 31, 2017 and 2016 , we had received $117 million and $89 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $54 million and $66 million as of December 31, 2017 and 2016 , respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for the majority of our net-cash arrangements. We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. |
Noncontrolling Interests | Noncontrolling Interests Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Following our sale of SLC Pipeline LLC in the fourth quarter of 2017, we no longer have any noncontrolling interests in consolidated subsidiaries. See Note 11 for additional discussion regarding our noncontrolling interests. |
Asset Retirement Obligations | Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily related to our Transportation and Facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. |
Fair Value Measurements | Fair Value Measurements Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels. The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest rate derivatives and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period. See Note 12 for further discussion. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We expect to adopt this ASU on January 1, 2019 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows. In May 2017, the FASB issued ASU 2017-09, Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Under the new guidance, modification accounting is required only if the fair value (or calculated value or intrinsic value, if such alternative method is used), the vesting conditions, or the classification of the award (equity or liability) changes as a result of the change in terms or conditions. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . The ASU clarifies what type of transactions involving nonfinancial assets are covered by the ASU and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606. We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of approximately $110 million related to the retained non-controlling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017. See Note 8 for discussion of our investments in unconsolidated entities. In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment . The amendments within this ASU eliminate Step 2 from the goodwill impairment test, which currently requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Under the amended standard, goodwill impairment will instead be measured using Step 1 of the goodwill impairment test with goodwill impairment being equal to the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in the first quarter of 2017 and applied the amended standard to our 2017 annual goodwill impairment test. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which improves the guidance for determining whether a transaction involves the purchase or disposal of a business or an asset. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We adopted this ASU on January 1, 2018 and will apply the new guidance to applicable transactions occurring after that date. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) , requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 31, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our statement of cash flows. In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory , to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted in the first interim period of an annual reporting period. We adopted this ASU on January 1, 2018. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control , changing how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This guidance was effective for interim and annual periods beginning after December 31, 2016. We adopted this ASU on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this ASU on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position results of operations and cash flows. In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which simplified several aspects of the accounting for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This ASU is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted the applicable provisions of the ASU on January 1, 2017 and (i) elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption and (ii) classify cash paid for taxes when directly withholding units from an employee’s award for tax-withholding purposes as a financing activity on our Consolidated Statement of Cash Flows. Our adoption did not have a material impact on our financial position or results of operations for the periods presented. We reclassified approximately $7 million and $14 million , respectively, of cash outflows from operating activities to financing activities for the years ended December 31, 2016 and 2015 related to cash paid for minimum statutory withholding requirements for which we withheld units from employees’ awards. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This ASU will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this ASU on January 1, 2019. We are currently evaluating the effect that adopting this ASU will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our Consolidated Balance Sheet. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires entities to measure inventory at the lower of cost and net realizable value; however, inventory measured using last-in, first-out and the retail inventory method is unchanged by this ASU. This guidance was effective for interim and annual periods beginning after December 15, 2016, with prospective application required. We adopted this ASU on January 1, 2017. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, followed by a series of related accounting standard updates (collectively referred to as “Topic 606”) with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. Topic 606 also requires additional disclosures. Topic 606 can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption and is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting Topic 606 on each type of revenue contract entered into with customers, and our implementation team effected changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We did not identify any material revenue recognition timing differences under Topic 606 as compared to our policies in effect prior to adoption. In addition, we will have an increase in disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. The cumulative effect of the adoption of Topic 606 was not material. |
Net Income Per Common Unit | After consideration of distributions to preferred unitholders (whether paid in cash or in-kind), basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our general partner (for periods prior to the Simplification Transactions), limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units and the assumption by us of AAP’s debt. In addition, we may issue to AAP up to 0.8 million common units in connection with certain AAP Management Units becoming earned in future periods. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. See Note 1 for additional discussion of the Simplification Transactions. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities, and for periods prior to the closing of the Simplification Transactions, the 2% general partner’s interest and IDRs) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units, (ii) our LTIP awards and (iii) common units that are issuable to AAP when certain AAP Management Units become earned. See Note 11 for additional information regarding our Series A preferred units. See Note 16 for a complete discussion of our LTIP awards and the AAP Management Units. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the years ended December 31, 2017 and 2016 as the effect was antidilutive. Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that were deemed to be dilutive during the three years ended December 31, 2017 were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. As none of the necessary conditions for the remaining AAP Management Units to become earned had been satisfied by December 31, 2017 , no common units issuable to AAP were contemplated in the calculation of diluted net income per common unit for any period presented. |
Inventory, Linefill and Base Gas and Long-term Inventory | Inventory primarily consists of crude oil, NGL and natural gas in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. During the years ended December 31, 2017 , 2016 and 2015 , we recorded charges of $35 million , $3 million and $117 million , respectively, related to the writedown of our crude oil, NGL and natural gas inventory due to declines in prices. A portion of these inventory valuation adjustments was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil and NGL inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statement of Operations. See Note 12 for discussion of our derivative and risk management activities. Linefill and base gas in assets we own are recorded at historical cost and consist of crude oil, NGL and natural gas. We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks and caverns that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 5 for further discussion regarding impairment of long-lived assets. During 2017 , 2016 and 2015 , we did not recognize any impairments of linefill and base gas. Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at the average cost of the applicable inventory pools, and into long-term inventory, which is reflected as a separate line item in “Other assets” on our Consolidated Balance Sheets. |
Property and Equipment | We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods. We also classify gains and losses on sales of assets and asset impairments as a component of “Depreciation and amortization” in our Consolidated Statements of Operations. See Note 6 for a discussion of our disposition activities. In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized. We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. For the years ended December 31, 2017 , 2016 and 2015 , capitalized interest recorded to property and equipment was $17 million , $34 million and $49 million , respectively. In addition, we capitalize interest related to investments in certain unconsolidated entities. See Note 8 for additional information. We also capitalize expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred. |
Impairment of Long-Lived Assets | Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include: • whether there is an indication of impairment; • the grouping of assets; • the intention of “holding,” “abandoning” or “selling” an asset; • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and • if an impairment exists, the fair value of the asset or asset group. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods. |
Goodwill | Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. In accordance with FASB guidance, we test goodwill to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance provides for a quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. In the quantitative test, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then goodwill is impaired by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. |
Investments in Unconsolidated Entities | Investments in entities over which we have significant influence but not control are accounted for under the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on our Consolidated Balance Sheets. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature. Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. During the year ended December 31, 2017, we received $ 21 million as a return of investment from Settoon Towing, LLC related to the sale of certain of its marine assets. We generally fund our portion of development, construction or capital expansion projects of our equity method investees through capital contributions. Our contributions to these entities increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. During the years ended December 31, 2017 , 2016 and 2015 , we made cash contributions of $398 million , $288 million and $245 million , respectively, to certain of our equity method investees. The contributions for 2017 and 2015 are net of $6 million and $53 million , respectively, of returns of cash contributions made during the periods. In addition, we capitalized interest of $18 million , $13 million and $8 million during the years ended December 31, 2017 , 2016 and 2015 , respectively, related to contributions to unconsolidated entities for projects under development and construction. We anticipate that we will make additional contributions to Eagle Ford Terminals, Eagle Ford Pipeline, BridgeTex, Diamond and STACK in 2018 related to ongoing projects by such entities. Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $736 million and $758 million at December 31, 2017 and 2016 , respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The basis difference at both December 31, 2017 and 2016 is primarily related to our acquisition of an interest in BridgeTex in 2014. |
Intangible Assets | Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. |
Debt | In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. These letters of credit are issued under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil, NGL or natural gas is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. |
Income Allocation | Income Allocation We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Following the closing of the Simplification Transactions, net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders. In accordance with our partnership agreement, our Series A preferred unitholders are not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For periods prior to the Simplification Transactions, our general partner and common unitholders were allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner for distributions declared and paid following the close of each quarter and (ii) cash distributions to our Series A preferred unitholders. Our Series A preferred unitholders were not allocated income for paid-in-kind distributions for partners’ capital presentation purposes. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for distributions attributable to the period (whether paid in cash or in-kind) on our Series A and Series B preferred units. See Note 3 for additional information. |
Derivatives | We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. |
Derivative Hedge Accounting Documentation | When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. |
Derivative Hedge Effectiveness Determination | Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. |
Derivatives That Qualify for Hedge Accounting | For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. |
Derivatives That Do Not Qualify for Hedge Accounting | Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. |
Cash Settlements Associated with Derivative Activities | Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows. |
Offsetting Derivative Assets and Liabilities | Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. |
Fair Value Hierarchy Transfer | To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur. |
Income Taxes | Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions. Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. |
Concentration of Credit Risk | Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. |
Reimbursement of Expenses of Our General Partner and its Affiliates | We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. |
Loss Contingencies | To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. |
Environmental Matters | We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery. Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed. |
Operating Segments | Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM. Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. The measure of segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items including (i) gains or losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in segment adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash”. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. |
Net Income Per Common Unit (Tab
Net Income Per Common Unit (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Computation of basic and diluted net income per common unit | The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Year Ended December 31, 2017 2016 2015 Basic Net Income per Common Unit Net income attributable to PAA $ 856 $ 726 $ 903 Distributions to Series A preferred unitholders (142 ) (122 ) — Distributions to Series B preferred unitholders (11 ) — — Distributions to general partner — (412 ) (608 ) Distributions to participating securities (2 ) (4 ) (6 ) Undistributed loss allocated to general partner — 14 16 Other (16 ) (2 ) — Net income allocated to common unitholders (1) $ 685 $ 200 $ 305 Basic weighted average common units outstanding (2) 717 464 394 Basic net income per common unit $ 0.96 $ 0.43 $ 0.78 Diluted Net Income per Common Unit Net income attributable to PAA $ 856 $ 726 $ 903 Distributions to Series A preferred unitholders (142 ) (122 ) — Distributions to Series B preferred unitholders (11 ) — — Distributions to general partner — (412 ) (608 ) Distributions to participating securities (2 ) (4 ) (6 ) Undistributed loss allocated to general partner — 14 16 Other (16 ) (2 ) — Net income allocated to common unitholders (1) $ 685 $ 200 $ 305 Basic weighted average common units outstanding (2) 717 464 394 Effect of dilutive securities: LTIP units 1 2 2 Diluted weighted average common units outstanding 718 466 396 Diluted net income per common unit $ 0.95 $ 0.43 $ 0.77 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) We considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders. |
Inventory, Linefill and Base 31
Inventory, Linefill and Base Gas and Long-term Inventory (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Inventory, Linefill and Base Gas and Long-term Inventory | |
Schedule of inventory, linefill and base gas and long-term inventory | Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): December 31, 2017 December 31, 2016 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 7,800 barrels $ 402 $ 51.54 23,589 barrels $ 1,049 $ 44.47 NGL 10,774 barrels 294 $ 27.29 13,497 barrels 242 $ 17.93 Natural gas — Mcf — $ — 14,540 Mcf 32 $ 2.20 Other N/A 17 N/A N/A 20 N/A Inventory subtotal 713 1,343 Linefill and base gas Crude oil 12,340 barrels 719 $ 58.27 12,273 barrels 710 $ 57.85 NGL 1,597 barrels 45 $ 28.18 1,660 barrels 45 $ 27.11 Natural gas 24,976 Mcf 108 $ 4.32 30,812 Mcf 141 $ 4.58 Linefill and base gas subtotal 872 896 Long-term inventory Crude oil 1,870 barrels 105 $ 56.15 3,279 barrels 163 $ 49.71 NGL 2,167 barrels 59 $ 27.23 1,418 barrels 30 $ 21.16 Long-term inventory subtotal 164 193 Total $ 1,749 $ 2,432 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Components of property and equipment, net | Property and equipment, net is stated at cost and consisted of the following (in millions): Estimated Useful Lives (Years) December 31, 2017 2016 Pipelines and related facilities (1) 10 - 70 $ 9,585 $ 9,025 Storage, terminal and rail facilities 30 - 70 5,558 5,305 Trucking equipment and other 3 - 15 414 408 Construction in progress — 610 826 Office property and equipment 2 - 50 255 222 Land and other N/A 440 434 Property and equipment, gross 16,862 16,220 Accumulated depreciation (2,773 ) (2,348 ) Property and equipment, net $ 14,089 $ 13,872 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) - Alpha Holding Company, LLC | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
Schedule of assets acquired and liabilities assumed | The following table reflects the fair value determination (in millions): Identifiable assets acquired and liabilities assumed: Estimated Useful Lives (Years) Recognized amount Property and equipment 3 - 70 $ 299 Intangible assets 20 646 Goodwill N/A 269 Other assets and liabilities, net (including $4 million of cash acquired) N/A 1 $ 1,215 |
Schedule of amortization expense | Amortization expense was approximately $10 million for the period from February 14, 2017 through December 31, 2017, and the future amortization expense is estimated as follows for the next five years (in millions): 2018 $ 25 2019 $ 34 2020 $ 42 2021 $ 48 2022 $ 54 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of goodwill by segment and changes during the period | Goodwill by segment and changes in goodwill is reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2015 $ 815 $ 1,087 $ 503 $ 2,405 Foreign currency translation adjustments 6 3 1 10 Dispositions and reclassifications to assets held for sale (15 ) (56 ) — (71 ) Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344 Acquisitions 269 — — 269 Foreign currency translation adjustments 16 7 4 27 Dispositions and reclassifications to assets held for sale (21 ) (53 ) — (74 ) Balance at December 31, 2017 $ 1,070 $ 988 $ 508 $ 2,566 |
Investments in Unconsolidated35
Investments in Unconsolidated Entities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in and summarized financial information for entities accounted for under the equity method of accounting | Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at December 31, 2017 December 31, Entity (1) Type of Operation 2017 2016 Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) Crude Oil Pipeline 50% $ 69 $ — BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 50% 1,093 1,098 Butte Pipe Line Company Crude Oil Pipeline N/A — 11 Caddo Pipeline LLC Crude Oil Pipeline 50% 67 65 Cheyenne Pipeline LLC (“Cheyenne”) Crude Oil Pipeline 50% 29 30 Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50% 467 143 Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50% 378 372 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock (2) 50% 75 53 Frontier Aspen LLC Crude Oil Pipeline N/A — 45 Midway Pipeline LLC Crude Oil Pipeline 50% 20 — Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 217 213 Settoon Towing, LLC Barge Transportation Services 50% 69 87 STACK Pipeline LLC (“STACK”) Crude Oil Pipeline 50% 73 14 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 199 212 Total Investments in Unconsolidated Entities $ 2,756 $ 2,343 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) Asset is currently under construction by the entity and has not yet been placed in service. Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests. December 31, 2017 2016 Current assets $ 311 $ 303 Noncurrent assets $ 4,162 $ 3,558 Current liabilities $ 129 $ 241 Noncurrent liabilities $ 41 $ 162 Year Ended December 31, 2017 2016 2015 Revenues $ 938 $ 802 $ 769 Operating income $ 650 $ 469 $ 441 Net income $ 640 $ 452 $ 424 |
Other Long-Term Assets, Net (Ta
Other Long-Term Assets, Net (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Assets [Abstract] | |
Components of other long-term assets, net of accumulated amortization | Other long-term assets, net of accumulated amortization, consisted of the following (in millions): December 31, 2017 2016 Intangible assets (1) $ 1,265 $ 603 Other 60 48 1,325 651 Accumulated amortization (421 ) (361 ) $ 904 $ 290 (1) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 5 for a discussion of property and equipment. |
Components of intangible assets that have finite lives | Our intangible assets that have finite lives consisted of the following (in millions): December 31, 2017 December 31, 2016 Estimated Useful Cost Accumulated Net Cost Accumulated Net Customer contracts and relationships 1 – 20 $ 1,188 $ (383 ) $ 805 $ 529 $ (330 ) $ 199 Property tax abatement 7 – 13 38 (30 ) 8 38 (26 ) 12 Other agreements 25 – 70 39 (8 ) 31 36 (5 ) 31 $ 1,265 $ (421 ) $ 844 $ 603 $ (361 ) $ 242 |
Estimated amortization expense related to finite-lived intangible assets for the next five years | We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions): 2018 $ 63 2019 $ 68 2020 $ 74 2021 $ 75 2022 $ 76 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consisted of the following (in millions): December 31, December 31, SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively (1) $ — $ 563 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.6% and 1.8%, respectively (1) 664 750 Senior notes: 6.13% senior notes due January 2017 — 400 Other 73 2 Total short-term debt (2) 737 1,715 LONG-TERM DEBT Senior notes: 6.50% senior notes due May 2018 (3) — 600 8.75% senior notes due May 2019 (3) — 350 2.60% senior notes due December 2019 500 500 5.75% senior notes due January 2020 500 500 5.00% senior notes due February 2021 600 600 3.65% senior notes due June 2022 750 750 2.85% senior notes due January 2023 400 400 3.85% senior notes due October 2023 700 700 3.60% senior notes due November 2024 750 750 4.65% senior notes due October 2025 1,000 1,000 4.50% senior notes due December 2026 750 750 6.70% senior notes due May 2036 250 250 6.65% senior notes due January 2037 600 600 5.15% senior notes due June 2042 500 500 4.30% senior notes due January 2043 350 350 4.70% senior notes due June 2044 700 700 4.90% senior notes due February 2045 650 650 Unamortized discounts and debt issuance costs (67 ) (76 ) Senior notes, net of unamortized discounts and debt issuance costs 8,933 9,874 Other long-term debt: Commercial paper notes and senior secured hedged inventory facility borrowings (4) 247 247 Other 3 3 Total long-term debt 9,183 10,124 Total debt (5) $ 9,920 $ 11,839 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of December 31, 2017 and 2016 , as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) As of December 31, 2017 and 2016 , balance includes borrowings of $212 million and $410 million , respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) In December 2017, we redeemed our $600 million , 6.50% senior notes due May 2018 and our $350 million , 8.75% senior notes due May 2019. See the “Senior Notes—Senior Note Repayments and Redemptions” section below for further discussion. (4) As of December 31, 2017 and 2016 , we classified a portion of our commercial paper notes and senior secured hedged inventory facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis. (5) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.0 billion and $10.3 billion as of December 31, 2017 and 2016 , respectively. We estimated the aggregate fair value of these notes as of December 31, 2017 and 2016 to be approximately $9.1 billion and $10.4 billion , respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. |
Issuances of senior unsecured notes | The table below summarizes our issuances of senior unsecured notes during 2016 and 2015 (in millions): Year Description Maturity Face Value Interest Payment Dates 2016 4.50% Senior Notes issued at 99.716% of face value December 2026 $ 750 June 15 and December 15 2015 4.65% Senior Notes issued at 99.846% of face value October 2025 $ 1,000 April 15 and October 15 |
Aggregate maturities of long-term debt | The following table presents the aggregate contractually scheduled maturities of such long-term debt for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs. Calendar Year Payment (in millions) 2018 $ 247 2019 500 2020 500 2021 600 2022 750 Thereafter 6,653 |
Partners' Capital and Distrib38
Partners' Capital and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Partners' Capital Notes [Abstract] | |
Activity for preferred and common units | The following table presents the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Common Units Outstanding at December 31, 2014 — — 375,107,793 Sales of common units — — 22,133,904 Issuances of common units under LTIP — — 485,927 Outstanding at December 31, 2015 — — 397,727,624 Sale of Series A preferred units 61,030,127 — — Issuances of Series A preferred units in connection with in-kind distributions 3,358,726 — — Sales of common units — — 26,278,288 Issuances of common units under LTIP — — 480,581 Issuance of common units in connection with Simplification Transactions (Note 1) — — 244,707,926 Outstanding at December 31, 2016 64,388,853 — 669,194,419 Issuances of Series A preferred units in connection with in-kind distributions 5,307,689 — — Sale of Series B preferred units — 800,000 — Sales of common units — — 54,119,893 Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 6) — — 1,252,269 Issuances of common units under LTIP — — 622,557 Outstanding at December 31, 2017 69,696,542 800,000 725,189,138 |
Issuance of common units | The following table summarizes our sales of common units (net proceeds in millions): Year Type of Offering Common Units Issued Net Proceeds (1) (2) 2017 Continuous Offering Program 4,033,567 $ 129 (3) 2017 Omnibus Agreement (4) 50,086,326 (5) 1,535 2017 Total 54,119,893 $ 1,664 2016 Total Continuous Offering Program 26,278,288 $ 805 (3) 2015 Continuous Offering Program 1,133,904 $ 59 (3) 2015 Underwritten Offering 21,000,000 1,062 2015 Total 22,133,904 $ 1,121 (1) Amounts are net of costs associated with the offerings. (2) For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of $9 million and $22 million during 2016 and 2015 , respectively. (3) We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid $1 million , $8 million and $1 million of such commissions during 2017 , 2016 and 2015 , respectively. (4) Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, PAGP used the net proceeds from the sale of PAGP Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of PAGP Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to purchase from us an equivalent number of our common units. (5) Includes (i) approximately 1.8 million common units issued to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and (ii) 48.3 million common units issued to AAP in connection with PAGP’s March 2017 underwritten offering. |
Schedule of distributions paid | The following table details distributions paid to common unitholders (and, prior to the Simplification Transactions, our general partner) during the year presented (in millions, except per unit data): Distributions Paid Distributions per common unit Year Public AAP (1) Total 2017 $ 849 $ 537 $ 1,386 $ 1.95 2016 $ 1,062 $ 565 $ 1,627 $ 2.65 2015 $ 1,081 $ 590 $ 1,671 $ 2.76 (1) Prior to the Simplification Transactions, our general partner was entitled to receive (i) distributions with respect to its 2% indirect general partner interest and (ii) as the holder of our IDRs, incentive distributions if the amount we distributed with respect to any quarter exceeded certain specified levels. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us to AAP of approximately 244.7 million common units. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or general partner interest. During the year ended December 31, 2017, AAP received distributions on the common units it owned. |
Derivatives and Risk Manageme39
Derivatives and Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivatives and Risk Management Activities | |
Impact of derivative activities recognized in earnings | A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Year Ended December 31, 2017 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (188 ) $ (188 ) Field operating costs — (10 ) (10 ) Depreciation and amortization (3 ) — (3 ) Interest Rate Derivatives Interest expense, net (18 ) — (18 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 8 8 Preferred Distribution Rate Reset Option Other income/(expense), net — 13 13 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (21 ) $ (177 ) $ (198 ) Year Ended December 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 2 $ (344 ) $ (342 ) Transportation segment revenues — 5 5 Interest Rate Derivatives Interest expense, net (14 ) — (14 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (3 ) (3 ) Preferred Distribution Rate Reset Option Other income/(expense), net — 30 30 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (12 ) $ (312 ) $ (324 ) Year Ended December 31, 2015 Location of Gain/(Loss) Derivatives in Hedging Relationships (1) (2) Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ 56 $ 152 $ 208 Transportation segment revenues — 8 8 Field operating costs — (18 ) (18 ) Interest Rate Derivatives Interest expense, net (11 ) — (11 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (31 ) (31 ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ 45 $ 111 $ 156 (1) During the year ended December 31, 2017, we reclassified losses of approximately $10 million to Interest expense, net. During the year ended December 31, 2016, we reclassified losses of approximately $2 million to Supply and Logistics segment revenues and $2 million to Interest expense, net. During the year ended December 31, 2015, we reclassified a loss of approximately $4 million to Interest expense, net. Each reclassification from AOCI to earnings was due to anticipated hedged transactions being probable of not occurring. (2) Amounts in Interest expense, net include a loss of $4 million during the year ended December 31, 2016 attributable to the ineffective portion of cash flow hedges. No ineffectiveness was recognized for cash flow hedges during the years ended December 31, 2017 or 2015. |
Summary of derivative assets and liabilities on Consolidated Balance Sheets on a gross basis | The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Interest rate derivatives Other current liabilities $ 2 Other current liabilities $ (27 ) Other long-term liabilities and deferred credits (11 ) Total derivatives designated as hedging instruments $ 2 $ (38 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 73 Other current assets $ (227 ) Other long-term assets, net 1 Other current liabilities (131 ) Other current liabilities 5 Other long-term liabilities and deferred credits (5 ) Other long-term liabilities and deferred credits 3 Foreign currency derivatives Other current assets 6 Other current assets (2 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (22 ) Total derivatives not designated as hedging instruments $ 88 $ (387 ) Total derivatives $ 90 $ (425 ) The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Interest rate derivatives $ — Other current liabilities $ (23 ) Other long-term liabilities and deferred credits (27 ) Total derivatives designated as hedging instruments $ — $ (50 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 101 Other current assets $ (344 ) Other long-term assets, net 2 Other long-term assets, net (1 ) Other long-term liabilities and deferred credits 2 Other current liabilities (14 ) Other long-term liabilities and deferred credits (34 ) Foreign currency derivatives Other current liabilities 3 Other current liabilities (6 ) Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (32 ) Total derivatives not designated as hedging instruments $ 108 $ (431 ) Total derivatives $ 108 $ (481 ) |
Schedule of net broker receivable (payable) | The following table provides the components of our net broker receivable/(payable): December 31, 2017 December 31, 2016 Initial margin $ 48 $ 119 Variation margin posted 164 291 Net broker receivable $ 212 $ 410 |
Schedule of derivative financial assets that are subject to offsetting, including enforceable master netting arrangements | The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): December 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 90 $ (425 ) $ 108 $ (481 ) Netting adjustment (239 ) 239 (350 ) 350 Cash collateral paid 212 — 410 — Net position - asset/(liability) $ 63 $ (186 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 167 $ — Other long-term assets, net 1 — 1 — Other current liabilities — (151 ) — (40 ) Other long-term liabilities and deferred credits — (35 ) — (91 ) $ 63 $ (186 ) $ 168 $ (131 ) |
Schedule of derivative financial liabilities that are subject to offsetting, including enforceable master netting arrangements | The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): December 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 90 $ (425 ) $ 108 $ (481 ) Netting adjustment (239 ) 239 (350 ) 350 Cash collateral paid 212 — 410 — Net position - asset/(liability) $ 63 $ (186 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 167 $ — Other long-term assets, net 1 — 1 — Other current liabilities — (151 ) — (40 ) Other long-term liabilities and deferred credits — (35 ) — (91 ) $ 63 $ (186 ) $ 168 $ (131 ) |
Net deferred gain/(loss) recognized in AOCI for derivatives | The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions): Year Ended December 31, 2017 2016 2015 Commodity derivatives, net $ — $ — $ 33 Interest rate derivatives, net (16 ) (33 ) (32 ) Total $ (16 ) $ (33 ) $ 1 |
Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy | The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions): Fair Value as of December 31, 2017 Fair Value as of December 31, 2016 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 5 $ (278 ) $ (8 ) $ (281 ) $ (113 ) $ (171 ) $ (4 ) $ (288 ) Interest rate derivatives — (36 ) — (36 ) — (50 ) — (50 ) Foreign currency derivatives — 4 — 4 — (3 ) — (3 ) Preferred Distribution Rate Reset Option — — (22 ) (22 ) — — (32 ) (32 ) Total net derivative asset/(liability) $ 5 $ (310 ) $ (30 ) $ (335 ) $ (113 ) $ (224 ) $ (36 ) $ (373 ) (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. |
Reconciliation of changes in fair value of derivatives classified as Level 3 | The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions): Year Ended December 31, 2017 2016 Beginning Balance $ (36 ) $ 11 Net gains for the period included in earnings 12 28 Settlements 4 (10 ) Derivatives entered into during the period (10 ) (65 ) Ending Balance $ (30 ) $ (36 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ 5 $ (36 ) |
Interest Rate Swaps | |
Derivatives and Risk Management Activities | |
Schedule of terms of forward starting interest rate derivatives | The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2017 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 16 forward starting swaps (30-year) $ 400 6/15/2018 2.86 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge |
Foreign Currency Derivatives | |
Derivatives and Risk Management Activities | |
Summary of open forward exchange contracts | The following table summarizes our open forward exchange contracts as of December 31, 2017 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2018 $ 87 $ 109 $1.00 - $1.26 Forward exchange contracts that exchange USD for CAD: 2018 $ 645 $ 816 $1.00 - $1.27 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Components of income tax expense | Components of income tax expense are as follows (in millions): Year Ended December 31, 2017 2016 2015 Current income tax expense: State income tax $ 1 $ 2 $ 1 Canadian federal and provincial income tax 27 83 83 Total current income tax expense $ 28 $ 85 $ 84 Deferred income tax expense/(benefit): Canadian federal and provincial income tax $ 16 $ (60 ) $ 16 Total deferred income tax expense/(benefit) $ 16 $ (60 ) $ 16 Total income tax expense $ 44 $ 25 $ 100 |
Summary of differences between tax expense based on the statutory federal income tax rate and the effective income tax expense | The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions): Year Ended December 31, 2017 2016 2015 Income before tax $ 902 $ 755 $ 1,006 Partnership earnings not subject to current Canadian tax (756 ) (723 ) (773 ) $ 146 $ 32 $ 233 Canadian federal and provincial corporate tax rate 27 % 27 % 26 % Income tax at statutory rate $ 39 $ 8 $ 61 Canadian withholding tax $ 2 $ 13 $ 14 Canadian permanent differences and rate changes 2 2 24 State income tax 1 2 1 Total income tax expense $ 44 $ 25 $ 100 |
Deferred tax assets and liabilities | Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions): December 31, 2017 2016 Deferred tax assets: Derivative instruments $ 74 $ 49 Book accruals in excess of current tax deductions 22 24 Net operating losses 3 4 Total deferred tax assets 99 77 Deferred tax liabilities: Property and equipment in excess of tax values (455 ) (394 ) Other (50 ) (41 ) Total deferred tax liabilities (505 ) (435 ) Net deferred tax liabilities $ (406 ) $ (358 ) Balance sheet classification of deferred tax assets/(liabilities): Other long-term assets, net $ 3 $ 4 Other long-term liabilities and deferred credits (409 ) (362 ) $ (406 ) $ (358 ) |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oxy | |
Related Party Transactions | |
Schedule of related party transactions | The impact to our Consolidated Statements of Operations from those transactions is included below (in millions): Year Ended December 31, 2017 2016 2015 Revenues $ 920 $ 655 $ 866 Purchases and related costs (1) $ (253 ) $ 42 $ 41 (1) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): December 31, 2017 2016 Trade accounts receivable and other receivables $ 1,075 $ 789 Accounts payable $ 990 $ 836 |
Equity-Indexed Compensation P42
Equity-Indexed Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity-Indexed Compensation Plans | |
Summary of shares authorized | The following is a summary of the awards authorized under our LTIPs as of December 31, 2017 (in millions): LTIP PAA LTIP Awards Authorized Plains All American 2013 Long-Term Incentive Plan 13.1 Plains All American PNG Successor Long-Term Incentive Plan 1.3 Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 10.8 Total 25.2 |
Summary of expense recognized and the value of vested LTIP awards under equity-indexed compensation plans | The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions): Year Ended December 31, 2017 2016 2015 Equity-indexed compensation expense $ 41 $ 60 $ 27 LTIP unit-settled vestings $ 16 $ 24 $ 37 LTIP cash-settled vestings $ 25 $ 28 $ 66 |
Estimated equity-indexed compensation plan fair value amortization | We estimate that the remaining fair value will be recognized in expense as shown below (in millions): Year Equity-Indexed Compensation Plan Fair Value Amortization (1) 2018 $ 42 2019 21 2020 9 2021 2 2022 1 Total $ 75 (1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2017 . |
LTIP | |
Equity-Indexed Compensation Plans | |
Summary of activity for equity-indexed compensation plans | Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): PAA Units (1) Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 7.3 $ 41.45 Granted 2.1 $ 28.76 Vested (2.1 ) $ 28.91 Cancelled or forfeited (0.4 ) $ 44.56 Outstanding at December 31, 2015 6.9 $ 41.23 Granted 4.5 $ 23.38 Vested (1.9 ) $ 45.91 Modified — $ (8.21 ) Cancelled or forfeited (0.6 ) $ 37.19 Outstanding at December 31, 2016 8.9 $ 29.62 Granted 0.9 $ 23.52 Vested (1.7 ) $ 42.12 Modified — $ (6.04 ) Cancelled or forfeited (0.8 ) $ 26.99 Outstanding at December 31, 2017 7.3 $ 24.68 (1) Approximately 0.6 million , 0.5 million and 0.5 million PAA common units were issued, net of tax withholding of approximately 0.2 million , 0.3 million and 0.3 million units during 2017 , 2016 and 2015 , respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 0.9 million , 1.1 million and 1.3 million units) that vested during 2017 , 2016 and 2015 , respectively, were settled in cash. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of future non-cancelable commitments | Future non-cancelable commitments related to these items at December 31, 2017 are summarized below (in millions): 2018 2019 2020 2021 2022 Thereafter Total Leases, rights-of-way easements and other (1) $ 188 $ 155 $ 127 $ 107 $ 90 $ 363 $ 1,030 Other commitments (2) 205 178 145 127 109 299 1,063 Total $ 393 $ 333 $ 272 $ 234 $ 199 $ 662 $ 2,093 (1) Includes operating and capital leases as defined by FASB guidance, as well as obligations for rights-of-way easements. Leases are primarily for (i) railcars, (ii) land and surface rentals, (iii) office buildings, (iv) pipeline assets and (v) vehicles and trailers. We recognize expense on a straight-line basis over the life of the agreement, as applicable. Lease expense for 2017 , 2016 and 2015 was $207 million , $198 million and $164 million , respectively. (2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $760 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Expense associated with these storage, transportation and throughput agreements was approximately $ 197 million , $ 157 million and $ 85 million for 2017, 2016 and 2015, respectively. |
Quarterly Financial Data (Una44
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly financial data (unaudited) | First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) (in millions, except per unit data) 2017 Total revenues $ 6,667 $ 6,078 $ 5,873 $ 7,605 $ 26,223 Gross margin (2) $ 665 $ 325 $ 112 $ 327 $ 1,429 Operating income $ 591 $ 257 $ 44 $ 261 $ 1,153 Net income $ 444 $ 189 $ 34 $ 191 $ 858 Net income attributable to PAA $ 444 $ 188 $ 33 $ 191 $ 856 Basic net income/(loss) per common unit $ 0.59 $ 0.21 $ (0.01 ) $ 0.19 $ 0.96 Diluted net income/(loss) per common unit $ 0.58 $ 0.21 $ (0.01 ) $ 0.19 $ 0.95 Cash distributions per common unit (3) $ 0.55 $ 0.55 $ 0.55 $ 0.30 $ 1.95 2016 Total revenues $ 4,111 $ 4,950 $ 5,170 $ 5,952 $ 20,182 Gross margin (2) $ 349 $ 219 $ 419 $ 286 $ 1,273 Operating income $ 282 $ 146 $ 349 $ 218 $ 994 Net income $ 203 $ 102 $ 298 $ 127 $ 730 Net income attributable to PAA $ 202 $ 101 $ 297 $ 126 $ 726 Basic net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Diluted net income/(loss) per common unit $ 0.07 $ (0.20 ) $ 0.40 $ 0.14 $ 0.43 Cash distributions per common unit (3) $ 0.70 $ 0.70 $ 0.70 $ 0.55 $ 2.65 (1) The sum of the four quarters may not equal the total year due to rounding. (2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization. (3) Represents cash distributions declared and paid in the period presented. |
Operating Segments (Tables)
Operating Segments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment financial data | The following tables reflect certain financial data for each segment (in millions): Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2017 Revenues: External customers (1) $ 1,021 $ 555 $ 25,056 $ (409 ) $ 26,223 Intersegment (2) 697 618 9 409 1,733 Total revenues of reportable segments $ 1,718 $ 1,173 $ 25,065 $ — $ 27,956 Equity earnings in unconsolidated entities $ 290 $ — $ — $ 290 Segment adjusted EBITDA $ 1,287 $ 734 $ 60 $ 2,081 Capital expenditures (3) $ 2,126 $ 312 $ 20 $ 2,458 Maintenance capital $ 120 $ 114 $ 13 $ 247 As of December 31, 2017 Total assets $ 12,661 $ 7,313 $ 5,377 $ 25,351 Investments in unconsolidated entities $ 2,681 $ 75 $ — $ 2,756 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2016 Revenues: External customers (1) $ 954 $ 546 $ 19,004 $ (322 ) $ 20,182 Intersegment (2) 630 561 14 322 1,527 Total revenues of reportable segments $ 1,584 $ 1,107 $ 19,018 $ — $ 21,709 Equity earnings in unconsolidated entities $ 195 $ — $ — $ 195 Segment adjusted EBITDA $ 1,141 $ 667 $ 359 $ 2,167 Capital expenditures (3) $ 1,063 $ 577 $ 54 $ 1,694 Maintenance capital $ 121 $ 55 $ 10 $ 186 As of December 31, 2016 Total assets $ 10,917 $ 7,556 $ 5,737 $ 24,210 Investments in unconsolidated entities $ 2,290 $ 53 $ — $ 2,343 Transportation Facilities Supply and Intersegment Total Year Ended December 31, 2015 Revenues: External customers (1) $ 953 $ 528 $ 21,927 $ (256 ) $ 23,152 Intersegment (2) 641 522 18 256 1,437 Total revenues of reportable segments $ 1,594 $ 1,050 $ 21,945 $ — $ 24,589 Equity earnings in unconsolidated entities $ 183 $ — $ — $ 183 Segment adjusted EBITDA $ 1,056 $ 588 $ 568 $ 2,212 Capital expenditures (3) $ 1,278 $ 813 $ 184 $ 2,275 Maintenance capital $ 144 $ 68 $ 8 $ 220 As of December 31, 2015 Total assets $ 10,345 $ 7,330 $ 4,613 $ 22,288 Investments in unconsolidated entities $ 1,998 $ 29 $ — $ 2,027 (1) Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM. (2) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. (3) Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities. |
Reconciliation of segment profit to net income attributable to PAA | The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Year Ended December 31, 2017 2016 2015 Segment adjusted EBITDA $ 2,081 $ 2,167 $ 2,212 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (45 ) (50 ) (45 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 46 (404 ) (110 ) Long-term inventory costing adjustments (4) 24 58 (99 ) Deficiencies under minimum volume commitments, net (5) (2 ) (46 ) — Equity-indexed compensation expense (6) (23 ) (33 ) (27 ) Net gain/(loss) on foreign currency revaluation (7) 26 (9 ) 29 Line 901 incident (8) (32 ) — (83 ) Significant acquisition-related expenses (9) (6 ) — — Depreciation and amortization (626 ) (494 ) (432 ) Interest expense, net (510 ) (467 ) (432 ) Other income/(expense), net (31 ) 33 (7 ) Income before tax 902 755 1,006 Income tax expense (44 ) (25 ) (100 ) Net income 858 730 906 Net income attributable to noncontrolling interests (2 ) (4 ) (3 ) Net income attributable to PAA $ 856 $ 726 $ 903 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization and gains or losses on significant asset sales of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for the year prior to 2016 were not significant to segment adjusted EBITDA ( $13 million for the year ended December 31, 2015). (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in units. (7) Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 17 for additional information regarding the Line 901 incident. (9) Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the year ended December 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance. Acquisition-related expenses for the 2016 and 2015 periods were not significant to segment adjusted EBITDA. |
Revenues attributable to geographic areas | We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions): Year Ended December 31, Revenues (1) 2017 2016 2015 United States $ 21,443 $ 15,599 $ 18,701 Canada 4,780 4,583 4,451 $ 26,223 $ 20,182 $ 23,152 (1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped. |
Long-lived assets attributable to geographic areas | December 31, Long-Lived Assets (1) 2017 2016 United States $ 17,167 $ 16,041 Canada 4,179 3,895 $ 21,346 $ 19,936 (1) Excludes long-term derivative assets and long-term deferred tax assets. |
Organization and Basis of Con46
Organization and Basis of Consolidation and Presentation (Details) shares in Millions, $ in Millions | Nov. 15, 2016USD ($)shares | Dec. 31, 2017segmentshares | Nov. 14, 2016 |
Organization and basis of presentation | |||
Operating segments number | segment | 3 | ||
Limited partner interest | 98.00% | ||
AAP | |||
Organization and basis of presentation | |||
Limited partner interest (units) | 284 | ||
Limited partner interest | 36.00% | ||
AAP | PAGP | |||
Organization and basis of presentation | |||
Limited partner interest | 55.00% | ||
Simplification Transactions | PAA GP | |||
Organization and basis of presentation | |||
Economic ownership interest converted into non-economic interest | 2.00% | ||
AAP senior secured credit agreement | Simplification Transactions | AAP | |||
Organization and basis of presentation | |||
Debt assumed | $ | $ 642 | ||
Common Units | Simplification Transactions | AAP | |||
Organization and basis of presentation | |||
Units to be issued in the future (in units) | 0.8 | ||
Common Units | Simplification Transactions | AAP | |||
Organization and basis of presentation | |||
Units agreed to be issued in connection with the Simplification Transactions | 245.5 | ||
Units to be issued in the future (in units) | 0.8 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Minimum Volume Commitments (Details) - Minimum Volume Commitments - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Minimum Volume Commitments | ||
Total counterparty deficiencies | $ 57 | $ 66 |
Deferred revenue | 37 | 54 |
Deficiencies not yet billed or collected | $ 20 | $ 12 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Various Policies (Details) $ in Millions | Dec. 31, 2017USD ($)$ / bbl | Feb. 29, 2016$ / bbl | Jun. 30, 2014$ / bbl | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Foreign Currency Transactions | ||||||
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities | $ 21 | $ (8) | $ 21 | |||
Cash and Cash Equivalents | ||||||
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents | $ 60 | 60 | 66 | |||
Accounts Receivable | ||||||
NYMEX WTI oil price (in dollars per bbl) | $ / bbl | 60.42 | |||||
Advance cash payments received from third parties to mitigate credit risk | $ 117 | 117 | 89 | |||
Standby letters of credit | 54 | $ 54 | $ 66 | |||
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date | 30 days | 30 days | ||||
Allowance for doubtful accounts receivable | 3 | $ 3 | $ 3 | |||
Asset Retirement Obligations | ||||||
Fair value of asset retirement obligations | $ 103 | $ 103 | $ 44 | |||
Maximum | ||||||
Accounts Receivable | ||||||
NYMEX WTI oil price (in dollars per bbl) | $ / bbl | 107.26 | |||||
Minimum | ||||||
Accounts Receivable | ||||||
NYMEX WTI oil price (in dollars per bbl) | $ / bbl | 26.21 |
Summary of Significant Accoun49
Summary of Significant Accounting Policies - Recent Accounting Pronouncements (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jan. 01, 2018 | Dec. 31, 2014 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Increase in investments in unconsolidated entities | $ 2,756 | $ 2,343 | $ 2,027 | ||
Increase in partners' capital | 10,958 | 8,816 | 7,939 | $ 8,191 | |
Cash outflow reclassed from operating activities | 2,499 | 733 | 1,358 | ||
Cash outflow reclassed to financing activities | $ 943 | (556) | (800) | ||
ASU 2016-09 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Cash outflow reclassed from operating activities | 7 | 14 | |||
Cash outflow reclassed to financing activities | $ 7 | $ 14 | |||
Subsequent Event | ASU 2017-05 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Increase in investments in unconsolidated entities | $ 110 | ||||
Increase in partners' capital | $ 110 |
Net Income Per Common Unit (Det
Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Nov. 15, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Nov. 14, 2016 |
Basic Net Income per Common Unit | |||||||||||||
Net income attributable to PAA | $ 191 | $ 33 | $ 188 | $ 444 | $ 126 | $ 297 | $ 101 | $ 202 | $ 856 | $ 726 | $ 903 | ||
Distributions to general partner | (412) | (608) | |||||||||||
Distributions to participating securities | (2) | (4) | (6) | ||||||||||
Undistributed loss allocated to general partner | 14 | 16 | |||||||||||
Other | (16) | (2) | |||||||||||
Net income allocated to common unitholders | 685 | 200 | 305 | ||||||||||
Diluted Net Income per Common Unit | |||||||||||||
Net income attributable to PAA | $ 191 | $ 33 | $ 188 | $ 444 | $ 126 | $ 297 | $ 101 | $ 202 | 856 | 726 | 903 | ||
Distributions to general partner | (412) | (608) | |||||||||||
Distributions to participating securities | (2) | (4) | (6) | ||||||||||
Undistributed loss allocated to general partner | 14 | 16 | |||||||||||
Other | (16) | (2) | |||||||||||
Net income allocated to common unitholders | 685 | 200 | $ 305 | ||||||||||
Effect of dilutive securities: | |||||||||||||
General partner ownership interest | 2.00% | ||||||||||||
Series A Preferred Units | |||||||||||||
Basic Net Income per Common Unit | |||||||||||||
Distributions to preferred unitholders | (142) | (122) | |||||||||||
Diluted Net Income per Common Unit | |||||||||||||
Distributions to preferred unitholders | (142) | $ (122) | |||||||||||
Series B Preferred Units | |||||||||||||
Basic Net Income per Common Unit | |||||||||||||
Distributions to preferred unitholders | (11) | ||||||||||||
Diluted Net Income per Common Unit | |||||||||||||
Distributions to preferred unitholders | $ (11) | ||||||||||||
Common Units | |||||||||||||
Basic Net Income per Common Unit | |||||||||||||
Basic weighted average common units outstanding (in units) | 717 | 464 | 394 | ||||||||||
Basic net income per common unit (in dollars per unit) | $ 0.19 | $ (0.01) | $ 0.21 | $ 0.59 | $ 0.14 | $ 0.40 | $ (0.20) | $ 0.07 | $ 0.96 | $ 0.43 | $ 0.78 | ||
Diluted Net Income per Common Unit | |||||||||||||
Basic weighted average common units outstanding (in units) | 717 | 464 | 394 | ||||||||||
Effect of dilutive securities: | |||||||||||||
LTIP units (in units) | 1 | 2 | 2 | ||||||||||
Diluted weighted average common units outstanding (in units) | 718 | 466 | 396 | ||||||||||
Diluted net income per common unit (in dollars per unit) | $ 0.19 | $ (0.01) | $ 0.21 | $ 0.58 | $ 0.14 | $ 0.40 | $ (0.20) | $ 0.07 | $ 0.95 | $ 0.43 | $ 0.77 | ||
Simplification Transactions | PAA GP | |||||||||||||
Effect of dilutive securities: | |||||||||||||
Economic ownership interest converted into non-economic interest | 2.00% | ||||||||||||
Simplification Transactions | AAP | Common Units | |||||||||||||
Effect of dilutive securities: | |||||||||||||
Units to be issued in the future (in units) | 0.8 | ||||||||||||
Units issued in connection with the Simplification Transactions | 244.7 |
Inventory, Linefill and Base 51
Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)$ / Mcf$ / bblMcfbbl | Dec. 31, 2016USD ($)$ / Mcf$ / bblMcfbbl | Dec. 31, 2015USD ($) | |
Inventory-related disclosures | |||
Charge related to the write-down of inventory | $ 35 | $ 3 | $ 117 |
Inventory by category | |||
Inventory | 713 | 1,343 | |
Linefill and base gas | 872 | 896 | |
Long-term inventory | 164 | 193 | |
Total | $ 1,749 | $ 2,432 | |
Crude oil | |||
Inventory by category | |||
Inventory, Volumes (in barrels or in Mcf) | bbl | 7,800 | 23,589 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 12,340 | 12,273 | |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 1,870 | 3,279 | |
Inventory | $ 402 | $ 1,049 | |
Linefill and base gas | 719 | 710 | |
Long-term inventory | $ 105 | $ 163 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 51.54 | 44.47 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 58.27 | 57.85 | |
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 56.15 | 49.71 | |
NGL | |||
Inventory by category | |||
Inventory, Volumes (in barrels or in Mcf) | bbl | 10,774 | 13,497 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 1,597 | 1,660 | |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 2,167 | 1,418 | |
Inventory | $ 294 | $ 242 | |
Linefill and base gas | 45 | 45 | |
Long-term inventory | $ 59 | $ 30 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 27.29 | 17.93 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 28.18 | 27.11 | |
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 27.23 | 21.16 | |
Natural gas | |||
Inventory by category | |||
Inventory, Volumes (in barrels or in Mcf) | Mcf | 0 | 14,540 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf | 24,976 | 30,812 | |
Inventory | $ 0 | $ 32 | |
Linefill and base gas | $ 108 | $ 141 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / Mcf | 0 | 2.20 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf | 4.32 | 4.58 | |
Other | |||
Inventory by category | |||
Inventory | $ 17 | $ 20 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property and Equipment | |||
Capitalized interest | $ 35 | $ 47 | $ 57 |
Property and equipment, gross | 16,862 | 16,220 | |
Accumulated depreciation | (2,773) | (2,348) | |
Property and equipment, net | 14,089 | 13,872 | |
Depreciation expense | 463 | 470 | 380 |
Pipelines and related facilities | |||
Property and Equipment | |||
Property and equipment, gross | $ 9,585 | 9,025 | |
Pipelines and related facilities | Minimum | |||
Property and Equipment | |||
Estimated useful lives | 10 years | ||
Pipelines and related facilities | Maximum | |||
Property and Equipment | |||
Estimated useful lives | 70 years | ||
Storage, terminal and rail facilities | |||
Property and Equipment | |||
Property and equipment, gross | $ 5,558 | 5,305 | |
Storage, terminal and rail facilities | Minimum | |||
Property and Equipment | |||
Estimated useful lives | 30 years | ||
Storage, terminal and rail facilities | Maximum | |||
Property and Equipment | |||
Estimated useful lives | 70 years | ||
Trucking equipment and other | |||
Property and Equipment | |||
Property and equipment, gross | $ 414 | 408 | |
Trucking equipment and other | Minimum | |||
Property and Equipment | |||
Estimated useful lives | 3 years | ||
Trucking equipment and other | Maximum | |||
Property and Equipment | |||
Estimated useful lives | 15 years | ||
Construction in progress | |||
Property and Equipment | |||
Property and equipment, gross | $ 610 | 826 | |
Office property and equipment | |||
Property and Equipment | |||
Property and equipment, gross | $ 255 | 222 | |
Office property and equipment | Minimum | |||
Property and Equipment | |||
Estimated useful lives | 2 years | ||
Office property and equipment | Maximum | |||
Property and Equipment | |||
Estimated useful lives | 50 years | ||
Land and other | |||
Property and Equipment | |||
Property and equipment, gross | $ 440 | 434 | |
Property, Plant and Equipment | |||
Property and Equipment | |||
Capitalized interest | 17 | 34 | 49 |
Rail And Other Terminal Assets | Depreciation and amortization | Facilities | |||
Property and Equipment | |||
Non-cash charge related to write-down of long-lived assets | $ 152 | $ 80 | $ 0 |
Acquisitions and Dispositions
Acquisitions and Dispositions - Acquisitions (Details) $ in Millions | Feb. 14, 2017USD ($)acontractmarket_interconnectmi | Feb. 28, 2017USD ($) | Dec. 31, 2017USD ($)bbl / d | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)acquisition | Dec. 31, 2015USD ($)acquisition |
Business Acquisition [Line Items] | ||||||
Cash consideration | $ 1,280 | $ 282 | $ 105 | |||
Amortization expense for finite-lived intangible assets | 54 | 44 | 49 | |||
Acquisition-related expenses | 6 | |||||
Goodwill recognized | 269 | |||||
Alpha Holding Company, LLC | ||||||
Business Acquisition [Line Items] | ||||||
Cash consideration | $ 1,215 | |||||
Length of gathering and transmission lines (in miles) | mi | 515 | |||||
Number of market interconnects | market_interconnect | 5 | |||||
Additional volume enhancements to gathering system (bbls per day) | bbl / d | 350,000 | |||||
Area of acreage dedication (gross acres) | a | 315,000 | |||||
Weighted-average useful life | 20 years | |||||
Acquisition-related expenses | $ 6 | |||||
Propane Marine Terminal | ||||||
Business Acquisition [Line Items] | ||||||
Cash consideration | $ 41 | |||||
Individually immaterial business acquisitions | ||||||
Business Acquisition [Line Items] | ||||||
Cash consideration | $ 289 | $ 105 | ||||
Number of acquisitions completed | acquisition | 2 | 3 | ||||
Goodwill recognized | $ 0 | $ 11 | ||||
Integrated System Of NGL Assets | ||||||
Business Acquisition [Line Items] | ||||||
Cash consideration | $ 204 | |||||
Advantage Joint Venture | ||||||
Business Acquisition [Line Items] | ||||||
Ownership interest | 50.00% | 50.00% | ||||
Frontier Aspen, LLC | ||||||
Business Acquisition [Line Items] | ||||||
Interest acquired | 28.00% | |||||
Acreage Dedication Contracts | Alpha Holding Company, LLC | ||||||
Business Acquisition [Line Items] | ||||||
Number of acreage dedication contracts acquired | contract | 5 | |||||
Weighted-average useful life | 20 years | |||||
Amortization expense for finite-lived intangible assets | $ 10 |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions | Feb. 14, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Business Acquisition [Line Items] | ||||
Goodwill | $ 2,566 | $ 2,344 | $ 2,405 | |
Alpha Holding Company, LLC | ||||
Business Acquisition [Line Items] | ||||
Property and equipment | $ 299 | |||
Intangible assets | 646 | |||
Goodwill | 269 | |||
Other assets and liabilities, net (including $4 million of cash acquired) | 1 | |||
Identifiable assets acquired and liabilities assumed | $ 1,215 | |||
Weighted-average useful life | 20 years | |||
Cash acquired | $ 4 | |||
Minimum | Alpha Holding Company, LLC | ||||
Business Acquisition [Line Items] | ||||
Estimated useful lives | 3 years | |||
Maximum | Alpha Holding Company, LLC | ||||
Business Acquisition [Line Items] | ||||
Estimated useful lives | 70 years |
Acquisitions and Dispositions55
Acquisitions and Dispositions - Future Amortization Expense (Details) $ in Millions | Dec. 31, 2017USD ($) |
Business Acquisition [Line Items] | |
2,018 | $ 63 |
2,019 | 68 |
2,020 | 74 |
2,021 | 75 |
2,022 | 76 |
Acreage Dedication Contracts | Alpha Holding Company, LLC | |
Business Acquisition [Line Items] | |
2,018 | 25 |
2,019 | 34 |
2,020 | 42 |
2,021 | 48 |
2,022 | $ 54 |
Acquisitions and Dispositions56
Acquisitions and Dispositions - Dispositions and Divestitures (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Dispositions | |||
Proceeds from sales of assets | $ 1,083 | $ 654 | $ 5 |
Disposed of by sale | Depreciation and amortization | |||
Dispositions | |||
Recognized gains/(losses) related to sale of assets, net | 43 | 100 | $ (2) |
Recognized gains related to sale of assets | 123 | 158 | |
Recognized losses related to sale of assets | 80 | 58 | |
Held for sale | Goodwill | Depreciation and amortization | |||
Dispositions | |||
Impairment losses | 15 | ||
Other current assets | Held for sale | |||
Dispositions | |||
Assets classified as held for sale | $ 80 | $ 275 | |
Red River Pipeline | |||
Dispositions | |||
Ownership interest disposed of | 40.00% |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in goodwill | ||
Balance at beginning of period | $ 2,344 | $ 2,405 |
Acquisitions | 269 | |
Foreign currency translation adjustments | 27 | 10 |
Dispositions and reclassifications to assets held for sale | (74) | (71) |
Balance at end of period | 2,566 | 2,344 |
Operating Segments | Transportation | ||
Changes in goodwill | ||
Balance at beginning of period | 806 | 815 |
Acquisitions | 269 | |
Foreign currency translation adjustments | 16 | 6 |
Dispositions and reclassifications to assets held for sale | (21) | (15) |
Balance at end of period | 1,070 | 806 |
Operating Segments | Facilities | ||
Changes in goodwill | ||
Balance at beginning of period | 1,034 | 1,087 |
Foreign currency translation adjustments | 7 | 3 |
Dispositions and reclassifications to assets held for sale | (53) | (56) |
Balance at end of period | 988 | 1,034 |
Operating Segments | Supply and Logistics | ||
Changes in goodwill | ||
Balance at beginning of period | 504 | 503 |
Foreign currency translation adjustments | 4 | 1 |
Balance at end of period | $ 508 | $ 504 |
Investments in Unconsolidated58
Investments in Unconsolidated Entities - Equity Method Investments (Details) - USD ($) shares in Millions, $ in Millions | Apr. 03, 2017 | Aug. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Investments in Unconsolidated Entities | ||||||
Investments in unconsolidated entities | $ 2,756 | $ 2,343 | $ 2,027 | |||
Value of units contributed | 40 | |||||
Return of investment from unconsolidated entities | 21 | |||||
Capital contributions to equity method investees excluding capitalized interest | 398 | 288 | 245 | |||
Return of cash contributions | 6 | 53 | ||||
Capitalized interest related to contributions to unconsolidated entities | 35 | 47 | 57 | |||
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets | $ 736 | 758 | ||||
Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | 50.00% | ||||
Investments in unconsolidated entities | $ 66.5 | $ 69 | 0 | |||
Payments to acquire investments | 26 | |||||
BridgeTex Pipeline Company, LLC (“BridgeTex”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 1,093 | 1,098 | ||||
Butte Pipe Line Company | ||||||
Investments in Unconsolidated Entities | ||||||
Investments in unconsolidated entities | $ 0 | 11 | ||||
Caddo Pipeline LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 67 | 65 | ||||
Cheyenne Pipeline LLC (“Cheyenne”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 29 | 30 | ||||
Ownership percentage sold | 50.00% | |||||
Diamond Pipeline LLC (“Diamond”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 467 | 143 | ||||
Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 378 | 372 | ||||
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 75 | 53 | ||||
Frontier Aspen LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Investments in unconsolidated entities | $ 0 | 45 | ||||
Midway Pipeline LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 20 | 0 | ||||
Saddlehorn Pipeline Company, LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 40.00% | |||||
Investments in unconsolidated entities | $ 217 | 213 | ||||
Settoon, Towing LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 69 | 87 | ||||
Return of investment from unconsolidated entities | $ 21 | |||||
STACK Pipeline LLC (“STACK”) | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 50.00% | |||||
Investments in unconsolidated entities | $ 73 | 14 | ||||
Ownership percentage sold | 50.00% | |||||
White Cliffs Pipeline, LLC | ||||||
Investments in Unconsolidated Entities | ||||||
Ownership interest | 36.00% | |||||
Investments in unconsolidated entities | $ 199 | 212 | ||||
Equity Method Investees | ||||||
Investments in Unconsolidated Entities | ||||||
Capitalized interest related to contributions to unconsolidated entities | $ 18 | $ 13 | $ 8 | |||
Advantage Joint Venture | Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) | ||||||
Investments in Unconsolidated Entities | ||||||
Purchase price | $ 133 | |||||
Common Units | Advantage Pipeline Holdings LLC (“Advantage Joint Venture”) | ||||||
Investments in Unconsolidated Entities | ||||||
Units contributed | 1.3 | |||||
Value of units contributed | $ 40 |
Investments in Unconsolidated59
Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Combined summarized financial information for unconsolidated entities | |||
Current assets | $ 311 | $ 303 | |
Noncurrent assets | 4,162 | 3,558 | |
Current liabilities | 129 | 241 | |
Noncurrent liabilities | 41 | 162 | |
Revenues | 938 | 802 | $ 769 |
Operating income | 650 | 469 | 441 |
Net income | $ 640 | $ 452 | $ 424 |
Other Long-Term Assets, Net -
Other Long-Term Assets, Net - Schedule of Long-term Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Long-Term Assets, Net | |||
Intangible assets | $ 1,265 | $ 603 | |
Other | 60 | 48 | |
Other long-term assets, gross | 1,325 | 651 | |
Accumulated amortization | (421) | (361) | |
Other long-term assets, net | 904 | 290 | |
Amortization expense for finite-lived intangible assets | $ 54 | $ 44 | $ 49 |
Other Long-Term Assets, Net 61
Other Long-Term Assets, Net - Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Finite-Lived Intangible Assets | ||
Cost | $ 1,265 | $ 603 |
Accumulated Amortization | (421) | (361) |
Net | 844 | 242 |
Estimated amortization expense related to finite-lived intangible assets for the next five years | ||
2,018 | 63 | |
2,019 | 68 | |
2,020 | 74 | |
2,021 | 75 | |
2,022 | 76 | |
Customer contracts and relationships | ||
Finite-Lived Intangible Assets | ||
Cost | 1,188 | 529 |
Accumulated Amortization | (383) | (330) |
Net | $ 805 | 199 |
Customer contracts and relationships | Minimum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 1 year | |
Customer contracts and relationships | Maximum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 20 years | |
Property tax abatement | ||
Finite-Lived Intangible Assets | ||
Cost | $ 38 | 38 |
Accumulated Amortization | (30) | (26) |
Net | $ 8 | 12 |
Property tax abatement | Minimum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 7 years | |
Property tax abatement | Maximum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 13 years | |
Other agreements | ||
Finite-Lived Intangible Assets | ||
Cost | $ 39 | 36 |
Accumulated Amortization | (8) | (5) |
Net | $ 31 | $ 31 |
Other agreements | Minimum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 25 years | |
Other agreements | Maximum | ||
Finite-Lived Intangible Assets | ||
Estimated Useful Lives | 70 years |
Debt - Schedule of Debt (Detail
Debt - Schedule of Debt (Details) - USD ($) | Dec. 31, 2017 | Jan. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
SHORT-TERM DEBT | ||||
Short-term debt | $ 737,000,000 | $ 1,715,000,000 | ||
LONG-TERM DEBT | ||||
Senior notes, net of unamortized discounts and debt issuance costs | 8,933,000,000 | 9,874,000,000 | ||
Noncurrent portion of other long-term debt | 250,000,000 | 250,000,000 | ||
Total long-term debt | 9,183,000,000 | 10,124,000,000 | ||
Total debt | 9,920,000,000 | 11,839,000,000 | ||
Commercial Paper | ||||
SHORT-TERM DEBT | ||||
Short-term notes and borrowings | $ 0 | $ 563,000,000 | ||
Weighted average interest rate, short-term (as a percent) | 2.40% | 1.60% | ||
Other | ||||
SHORT-TERM DEBT | ||||
Short-term debt | $ 73,000,000 | $ 2,000,000 | ||
Exchange Traded | ||||
SHORT-TERM DEBT | ||||
Short-term debt | 212,000,000 | 410,000,000 | ||
Senior secured hedged inventory facility | Line of Credit | ||||
SHORT-TERM DEBT | ||||
Short-term notes and borrowings | $ 664,000,000 | $ 750,000,000 | ||
Weighted average interest rate, short-term (as a percent) | 2.60% | 1.80% | ||
6.13% senior notes due January 2017 | Senior notes | ||||
SHORT-TERM DEBT | ||||
Senior notes, current portion | $ 0 | $ 400,000,000 | ||
Senior notes | ||||
LONG-TERM DEBT | ||||
Unamortized discounts and debt issuance costs | (67,000,000) | (76,000,000) | ||
Senior notes, net of unamortized discounts and debt issuance costs | 8,933,000,000 | 9,874,000,000 | ||
Debt instrument face value | 9,000,000,000 | 10,300,000,000 | ||
Senior notes | Level 2 | ||||
LONG-TERM DEBT | ||||
Debt instrument fair value | 9,100,000,000 | $ 10,400,000,000 | ||
Senior notes | 6.13% senior notes due January 2017 | ||||
LONG-TERM DEBT | ||||
Debt instrument, interest rate (as a percent) | 6.13% | 6.13% | ||
Senior notes | 6.50% senior notes due May 2018 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 0 | $ 600,000,000 | ||
Debt instrument, interest rate (as a percent) | 6.50% | 6.50% | ||
Senior notes | 8.75% senior notes due May 2019 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 0 | $ 350,000,000 | ||
Debt instrument, interest rate (as a percent) | 8.75% | 8.75% | ||
Senior notes | 2.60% senior notes due December 2019 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 500,000,000 | $ 500,000,000 | ||
Debt instrument, interest rate (as a percent) | 2.60% | 2.60% | ||
Senior notes | 5.75% senior notes due January 2020 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 500,000,000 | $ 500,000,000 | ||
Debt instrument, interest rate (as a percent) | 5.75% | 5.75% | ||
Senior notes | 5.00% senior notes due February 2021 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 600,000,000 | $ 600,000,000 | ||
Debt instrument, interest rate (as a percent) | 5.00% | 5.00% | ||
Senior notes | 3.65% senior notes due June 2022 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 750,000,000 | $ 750,000,000 | ||
Debt instrument, interest rate (as a percent) | 3.65% | 3.65% | ||
Senior notes | 2.85% senior notes due January 2023 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 400,000,000 | $ 400,000,000 | ||
Debt instrument, interest rate (as a percent) | 2.85% | 2.85% | ||
Senior notes | 3.85% senior notes due October 2023 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 700,000,000 | $ 700,000,000 | ||
Debt instrument, interest rate (as a percent) | 3.85% | 3.85% | ||
Senior notes | 3.60% senior notes due November 2024 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 750,000,000 | $ 750,000,000 | ||
Debt instrument, interest rate (as a percent) | 3.60% | 3.60% | ||
Senior notes | 4.65% senior notes due October 2025 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 1,000,000,000 | $ 1,000,000,000 | ||
Debt instrument, interest rate (as a percent) | 4.65% | 4.65% | 4.65% | |
Debt instrument face value | $ 1,000,000,000 | |||
Senior notes | 4.50% senior notes due December 2026 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 750,000,000 | $ 750,000,000 | ||
Debt instrument, interest rate (as a percent) | 4.50% | 4.50% | ||
Debt instrument face value | $ 750,000,000 | |||
Senior notes | 6.70% senior notes due May 2036 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 250,000,000 | $ 250,000,000 | ||
Debt instrument, interest rate (as a percent) | 6.70% | 6.70% | ||
Senior notes | 6.65% senior notes due January 2037 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 600,000,000 | $ 600,000,000 | ||
Debt instrument, interest rate (as a percent) | 6.65% | 6.65% | ||
Senior notes | 5.15% senior notes due June 2042 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 500,000,000 | $ 500,000,000 | ||
Debt instrument, interest rate (as a percent) | 5.15% | 5.15% | ||
Senior notes | 4.30% senior notes due January 2043 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 350,000,000 | $ 350,000,000 | ||
Debt instrument, interest rate (as a percent) | 4.30% | 4.30% | ||
Senior notes | 4.70% senior notes due June 2044 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 700,000,000 | $ 700,000,000 | ||
Debt instrument, interest rate (as a percent) | 4.70% | 4.70% | ||
Senior notes | 4.90% senior notes due February 2045 | ||||
LONG-TERM DEBT | ||||
Long-term debt, before deducting unamortized discounts and debt issuance costs | $ 650,000,000 | $ 650,000,000 | ||
Debt instrument, interest rate (as a percent) | 4.90% | 4.90% | ||
Commercial Paper | Senior secured hedged inventory facility | ||||
LONG-TERM DEBT | ||||
Noncurrent portion of other long-term debt | $ 247,000,000 | $ 247,000,000 | ||
Other | ||||
LONG-TERM DEBT | ||||
Noncurrent portion of other long-term debt | $ 3,000,000 | $ 3,000,000 |
Debt - Commercial Paper, Credit
Debt - Commercial Paper, Credit Facilities and Senior Notes (Details) | 1 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2017USD ($) | Jan. 31, 2017USD ($) | Aug. 31, 2016USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2017USD ($)extension | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 1,350,000,000 | $ 175,000,000 | $ 549,000,000 | |||||
Commercial Paper | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum aggregate borrowing capacity | $ 3,000,000,000 | 3,000,000,000 | ||||||
Senior secured hedged inventory facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum aggregate borrowing capacity | 1,900,000,000 | 1,900,000,000 | ||||||
Committed borrowing capacity | 1,400,000,000 | $ 1,400,000,000 | ||||||
Number of years by which maturity date of credit facility may be extended | 1 year | |||||||
Senior secured hedged inventory facility | Minimum | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility extensions available | extension | 1 | |||||||
Senior secured hedged inventory facility | Letters of credit | ||||||||
Debt Instrument [Line Items] | ||||||||
Committed borrowing capacity | 400,000,000 | $ 400,000,000 | ||||||
Senior unsecured revolving credit facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum aggregate borrowing capacity | 2,100,000,000 | 2,100,000,000 | ||||||
Committed borrowing capacity | 1,600,000,000 | $ 1,600,000,000 | ||||||
Number of years by which maturity date of credit facility may be extended | 1 year | |||||||
Senior unsecured revolving credit facility | Minimum | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility extensions available | extension | 1 | |||||||
Senior unsecured 364-day revolving credit facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Committed borrowing capacity | 1,000,000,000 | $ 1,000,000,000 | ||||||
Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument face value | 9,000,000,000 | $ 9,000,000,000 | $ 10,300,000,000 | |||||
6.13% senior notes due January 2017 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 400,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 6.13% | 6.13% | ||||||
6.50% senior notes due May 2018 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 600,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 6.50% | 6.50% | 6.50% | |||||
8.75% senior notes due May 2019 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 350,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 8.75% | 8.75% | 8.75% | |||||
5.88% senior notes due August 2016 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 175,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 5.88% | |||||||
5.25% senior notes due June 2015 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 150,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 5.25% | |||||||
3.95% senior notes due September 2015 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Repayments of senior notes | $ 400,000,000 | |||||||
Debt instrument, interest rate (as a percent) | 3.95% | |||||||
4.50% senior notes due December 2026 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument, interest rate (as a percent) | 4.50% | 4.50% | 4.50% | |||||
Offering price percentage | 99.716% | |||||||
Debt instrument face value | $ 750,000,000 | |||||||
4.65% senior notes due October 2025 | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument, interest rate (as a percent) | 4.65% | 4.65% | 4.65% | 4.65% | ||||
Offering price percentage | 99.846% | |||||||
Debt instrument face value | $ 1,000,000,000 | |||||||
Other income/(expense), net | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Loss on early redemption of senior notes | $ 40,000,000 | |||||||
Non-extending Lender | Senior secured hedged inventory facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Committed borrowing capacity | $ 60,000,000 | 60,000,000 | ||||||
Non-extending Lender | Senior unsecured revolving credit facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Committed borrowing capacity | $ 120,000,000 | $ 120,000,000 | ||||||
Consolidated finance subsidiary co-issuer | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Consolidated subsidiary, ownership interest held by the parent (as a percent) | 100.00% |
Debt - Maturities and Covenant
Debt - Maturities and Covenants (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | |||
Weighted-average maturity of long-term debt | 12 years | ||
Outstanding letters of credit | $ 166 | $ 73 | |
Maturities | |||
2,018 | 247 | ||
2,019 | 500 | ||
2,020 | 500 | ||
2,021 | 600 | ||
2,022 | 750 | ||
Thereafter | $ 6,653 | ||
Credit agreements | |||
Debt Instrument [Line Items] | |||
Coverage ratio of debt-to-EBITDA, maximum | 5 | ||
Ratio of debt-to-EBITDA during acquisition period, maximum | 5.50 | ||
Threshold for acquisition period qualification | $ 150 | ||
Credit agreements and commercial paper program | |||
Debt Instrument [Line Items] | |||
Total borrowings | 60,800 | 60,300 | $ 62,200 |
Total repayments | $ 61,500 | $ 61,000 | $ 61,300 |
Letters of credit | Maximum | |||
Debt Instrument [Line Items] | |||
Periods for which letters of credit are issued | 70 days |
Partners' Capital and Distrib65
Partners' Capital and Distributions - Activity for Series A Preferred Units and Common Units (Details) - shares | Jan. 28, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Nov. 14, 2016 |
Partners Capital and Distributions | |||||
Limited partner interest | 98.00% | ||||
General partner ownership interest | 2.00% | ||||
Series A Preferred Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, beginning of period (in units) | 64,388,853 | ||||
Sale of Series A preferred units (in units) | 61,000,000 | ||||
Balance, end of period (in units) | 69,696,542 | 64,388,853 | |||
Series B Preferred Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, end of period (in units) | 800,000 | ||||
Common Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, beginning of period (in units) | 669,194,419 | ||||
Sale of common units (in units) | 54,119,893 | 22,133,904 | |||
Balance, end of period (in units) | 725,189,138 | 669,194,419 | |||
Partners’ Capital Excluding Noncontrolling Interests | Limited Partners | Series A Preferred Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, beginning of period (in units) | 64,388,853 | 0 | 0 | 0 | |
Sale of Series A preferred units (in units) | 61,030,127 | ||||
Issuances of Series A preferred units in connection with in-kind distributions (in units) | 5,307,689 | 3,358,726 | |||
Balance, end of period (in units) | 69,696,542 | 64,388,853 | 0 | ||
Partners’ Capital Excluding Noncontrolling Interests | Limited Partners | Series B Preferred Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, beginning of period (in units) | 0 | 0 | 0 | 0 | |
Sale of Series B preferred units (in units) | 800,000 | ||||
Balance, end of period (in units) | 800,000 | 0 | 0 | ||
Partners’ Capital Excluding Noncontrolling Interests | Limited Partners | Common Units | |||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Balance, beginning of period (in units) | 669,194,419 | 397,727,624 | 375,107,793 | 375,107,793 | |
Sale of common units (in units) | 54,119,893 | 26,278,288 | 22,133,904 | ||
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 6) (in units) | 1,252,269 | ||||
Issuance of common units under LTIP (in units) | 622,557 | 480,581 | 485,927 | ||
Issuance of common units in connection with Simplification Transactions (in units) | 244,707,926 | ||||
Balance, end of period (in units) | 725,189,138 | 669,194,419 | 397,727,624 |
Partners' Capital and Distrib66
Partners' Capital and Distributions - Equity Offerings (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Partners Capital and Distributions | ||||
Issuance of units, net proceeds | $ 1,664 | $ 805 | $ 1,121 | |
General partners' proportionate capital contributions | 42 | 23 | ||
Continuous and Underwritten Offerings | General Partner | ||||
Partners Capital and Distributions | ||||
General partners' proportionate capital contributions | 9 | 22 | ||
Continuous Offering Program | ||||
Partners Capital and Distributions | ||||
Commissions to sales agents | $ 1 | $ 8 | $ 1 | |
Common Units | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 54,119,893 | 22,133,904 | ||
Issuance of units, net proceeds | $ 1,664 | $ 1,121 | ||
Common Units | Continuous Offering Program | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 4,033,567 | 26,278,288 | 1,133,904 | |
Issuance of units, net proceeds | $ 129 | $ 805 | $ 59 | |
Common Units | Omnibus Agreement | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 50,086,326 | |||
Issuance of units, net proceeds | $ 1,535 | |||
Common Units | Underwritten Offering | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 21,000,000 | |||
Issuance of units, net proceeds | $ 1,062 | |||
Omnibus Agreement | AAP | Common Units | Continuous Offering Program | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 1,800,000 | |||
Omnibus Agreement | AAP | Common Units | Underwritten Offering | ||||
Partners Capital and Distributions | ||||
Issuance of units (in units) | 48,300,000 | 48,300,000 |
Partners' Capital and Distrib67
Partners' Capital and Distributions - Preferred Unit Issuance (Details) $ / shares in Units, $ in Millions | Oct. 10, 2017USD ($)$ / sharesshares | Jan. 28, 2016USD ($)count$ / sharesshares | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 15, 2022$ / shares |
Partners Capital and Distributions | |||||
Net proceeds from sale of Series A preferred units | $ | $ 1,542 | ||||
Net proceeds from the sale of Series B preferred units | $ | $ 788 | ||||
Series A Preferred Units | |||||
Partners Capital and Distributions | |||||
Sale of Series A preferred units (in units) | shares | 61,000,000 | ||||
Sale of units, price per unit (in dollars per unit) | $ 26.25 | ||||
Transaction fee due to purchasers | 2.00% | ||||
Net proceeds from sale of Series A preferred units | $ | $ 1,600 | ||||
Quarterly distributions per unit (in dollars per unit) | $ 0.525 | ||||
Annualized distribution rate (in dollars per unit) | $ 2.10 | ||||
Series A preferred unit conversion ratio | 1 | ||||
Common unit closing price as a percentage of Issue Price, over which the entity has conversion option | 150.00% | ||||
Period for closing price of common units to be above threshold, to trigger conversion option | 20 days | ||||
Period after fifth and subsequent anniversaries of issuance for Distribution Rate Resets | 30 days | ||||
Number of distribution rate reset elections allowed | count | 1 | ||||
Distribution rate reset, basis spread on variable rate | 5.85% | ||||
Period after sixth anniversary of issuance, after which units may be redeemed if distribution rate has been reset | 30 days | ||||
Value of common units if exchanged for redemption of preferred units, as a percentage of average price | 95.00% | ||||
Redemption price as a percentage of Issue Price | 110.00% | ||||
Series B Preferred Units | |||||
Partners Capital and Distributions | |||||
Sale of units, price per unit (in dollars per unit) | $ 1,000 | ||||
Sale of Series B preferred units (in units) | shares | 800,000 | ||||
Net proceeds from the sale of Series B preferred units | $ | $ 788 | ||||
Liquidation preference (in dollars per unit) | $ 1,000 | ||||
Distribution rate percentage | 6.125% | ||||
Distribution rate per unit | $ 61.25 | ||||
Redemption price (in dollars per unit) | $ 1,020 | ||||
Redemption price percentage | 102.00% | ||||
Series B Preferred Units | Forecast | |||||
Partners Capital and Distributions | |||||
Percentage spread on top of LIBOR for distribution | 4.11% | ||||
Redemption price (in dollars per unit) | $ 1,000 |
Partners' Capital and Distrib68
Partners' Capital and Distributions - Schedule of Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Distribution Made to Limited Partner [Line Items] | |||
Total distributions paid | $ 1,399 | $ 1,631 | $ 1,674 |
Cash Distribution | |||
Distribution Made to Limited Partner [Line Items] | |||
Total distributions paid | $ 1,627 | $ 1,671 | |
Common Units | Cash Distribution | |||
Distribution Made to Limited Partner [Line Items] | |||
Total distributions paid | $ 1,386 | ||
Distributions per common unit (in dollars per unit) | $ 1.95 | $ 2.65 | $ 2.76 |
Public | Common Units | Cash Distribution | |||
Distribution Made to Limited Partner [Line Items] | |||
Distributions paid to limited partners | $ 849 | $ 1,062 | $ 1,081 |
AAP | Cash Distribution | |||
Distribution Made to Limited Partner [Line Items] | |||
Distributions paid to General Partner | $ 565 | $ 590 | |
AAP | Common Units | Cash Distribution | |||
Distribution Made to Limited Partner [Line Items] | |||
Distributions paid to limited partners | $ 537 |
Partners' Capital and Distrib69
Partners' Capital and Distributions - Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 14, 2018 | Jan. 08, 2018 | Nov. 15, 2017 | Nov. 15, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Nov. 14, 2016 |
Partners Capital and Distributions | ||||||||
Percentage of available cash distributed | 100.00% | |||||||
Number of days after end of quarter within which distributions must be paid to unitholders | 45 days | |||||||
General partner ownership interest | 2.00% | |||||||
Cash distributions paid | $ 1,399 | $ 1,631 | $ 1,674 | |||||
Partners’ Capital Excluding Noncontrolling Interests | ||||||||
Partners Capital and Distributions | ||||||||
Cash distributions paid | 1,397 | 1,627 | 1,671 | |||||
Series B Preferred Units | ||||||||
Partners Capital and Distributions | ||||||||
Dividends paid (in dollars per unit) | $ 5.9549 | |||||||
Preferred unit dividends | $ 5 | |||||||
Distributions payable | 6 | |||||||
Cash Distribution | ||||||||
Partners Capital and Distributions | ||||||||
Cash distributions paid | 1,627 | $ 1,671 | ||||||
Cash Distribution | Common Units | ||||||||
Partners Capital and Distributions | ||||||||
Cash distributions paid | 1,386 | |||||||
Cash Distribution | Common Units | Subsequent Event | Fourth quarter distribution | ||||||||
Partners Capital and Distributions | ||||||||
Distribution per common unit declared (in dollars per unit) | $ 0.30 | |||||||
Cash distributions paid | $ 218 | |||||||
Unit Distribution | Series A Preferred Units | Partners’ Capital Excluding Noncontrolling Interests | ||||||||
Partners Capital and Distributions | ||||||||
Distributions paid to unitholders | $ 139 | $ 89 | ||||||
Unit distributions (in units) | 5,307,689 | 3,358,726 | ||||||
Unit Distribution | Series A Preferred Units | Partners’ Capital Excluding Noncontrolling Interests | Subsequent Event | ||||||||
Partners Capital and Distributions | ||||||||
Distributions paid to unitholders | $ 37 | |||||||
Unit distributions (in units) | 1,393,926 | |||||||
Simplification Transactions | AAP | Common Units | ||||||||
Partners Capital and Distributions | ||||||||
Units issued in connection with the Simplification Transactions | 244,700,000 | |||||||
Simplification Transactions | PAA GP | ||||||||
Partners Capital and Distributions | ||||||||
Economic ownership interest converted into non-economic interest | 2.00% | |||||||
AAP | Cash Distribution | Common Units | ||||||||
Partners Capital and Distributions | ||||||||
Distributions paid to unitholders | $ 537 | |||||||
AAP | Cash Distribution | Common Units | Subsequent Event | Fourth quarter distribution | ||||||||
Partners Capital and Distributions | ||||||||
Distributions paid to unitholders | $ 85 | |||||||
Plains All American Pipeline L P [Member] | PAA GP | Simplification Transactions | ||||||||
Partners Capital and Distributions | ||||||||
Economic ownership interest converted into non-economic interest | 2.00% | |||||||
Plains All American Pipeline L P [Member] | AAP | Simplification Transactions | Common Units | ||||||||
Partners Capital and Distributions | ||||||||
Units issued in connection with the Simplification Transactions | 244,700,000 |
Partners' Capital and Distrib70
Partners' Capital and Distributions - Income Allocation (Details) | Dec. 31, 2017 |
Partners' Capital Notes [Abstract] | |
Net income allocation | 100.00% |
Partners' Capital and Distrib71
Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details) - SLC Pipeline LLC | 3 Months Ended |
Dec. 31, 2017 | |
Partners Capital and Distributions | |
Noncontrolling interests in subsidiaries | 75.00% |
Ownership percentage sold | 25.00% |
Derivatives and Risk Manageme72
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions | 12 Months Ended |
Dec. 31, 2017MWhMcfbbl | |
Net long position associated with crude oil purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 3.3 |
Net short time spread position hedging anticipated crude oil lease gathering purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 5.2 |
Crude oil grade basis position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 30.3 |
Net short position related to anticipated net sales of crude oil and NGL inventory | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 16.5 |
PLA net short position consisting of crude oil futures related to anticipated sales | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 1.1 |
PLA oil long call option position related to anticipated sales | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 0.9 |
Long natural gas position for natural gas purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | Mcf | 54.3 |
Short propane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 8.6 |
Short butane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 2.6 |
Short WTI position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 1 |
Long power position for power supply requirements | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in megawatt hours) | MWh | 0.4 |
Derivatives and Risk Manageme73
Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)contractCAD / $ | Dec. 31, 2016USD ($) | Dec. 31, 2017CADcontractCAD / $ | |
Currency Exchange Rate Risk Hedging: | |||
Gain on embedded derivative | $ 13 | $ 30 | |
16 forward starting swaps (30-year) | Cash Flow Hedging | |||
Currency Exchange Rate Risk Hedging: | |||
Number of interest rate derivatives | contract | 16 | 16 | |
Term of derivative contract | 30 years | ||
Notional amount of derivatives | $ 400 | ||
Average rate locked (percent) | 2.86% | 2.86% | |
8 forward starting swaps (30-year) | Cash Flow Hedging | |||
Currency Exchange Rate Risk Hedging: | |||
Number of interest rate derivatives | contract | 8 | 8 | |
Term of derivative contract | 30 years | ||
Notional amount of derivatives | $ 200 | ||
Average rate locked (percent) | 2.83% | 2.83% | |
Forward exchange contracts that exchange CAD for USD maturing in 2018 | |||
Currency Exchange Rate Risk Hedging: | |||
Notional amount of derivatives | $ 87 | CAD 109 | |
Average exchange rate (cad per usd) | CAD / $ | 1.26 | 1.26 | |
Forward exchange contracts that exchange USD for CAD maturing in 2018 | |||
Currency Exchange Rate Risk Hedging: | |||
Notional amount of derivatives | $ 645 | CAD 816 | |
Average exchange rate (cad per usd) | CAD / $ | 1.27 | 1.27 | |
Preferred Distribution Rate Reset Option | Series A Preferred Units | |||
Currency Exchange Rate Risk Hedging: | |||
Net derivative liability | $ 22 | 32 | |
Gain on embedded derivative | $ 13 | $ 30 |
Derivatives and Risk Manageme74
Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ (198) | $ (324) | $ 156 |
Loss on ineffective portion of cash flow hedges | 0 | 4 | 0 |
Commodity Derivatives | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (188) | (342) | 208 |
Commodity Derivatives | Transportation segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 5 | 8 | |
Commodity Derivatives | Field operating costs | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (10) | (18) | |
Commodity Derivatives | Depreciation and amortization | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (3) | ||
Interest Rate Derivatives | Interest expense, net | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (18) | (14) | (11) |
Foreign Currency Derivatives | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 8 | (3) | (31) |
Preferred Distribution Rate Reset Option | Other income/(expense), net | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 13 | 30 | |
Derivatives in Hedging Relationships | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (21) | (12) | 45 |
Derivatives in Hedging Relationships | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Loss recognized due to anticipated hedged transactions being probable of not occurring | 2 | ||
Derivatives in Hedging Relationships | Interest expense, net | |||
Impact of derivative activities recognized in earnings | |||
Loss recognized due to anticipated hedged transactions being probable of not occurring | 10 | 2 | 4 |
Derivatives in Hedging Relationships | Commodity Derivatives | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 2 | 56 | |
Derivatives in Hedging Relationships | Commodity Derivatives | Depreciation and amortization | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (3) | ||
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense, net | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (18) | (14) | (11) |
Derivatives Not Designated as a Hedge | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (177) | (312) | 111 |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (188) | (344) | 152 |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Transportation segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 5 | 8 | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | (10) | (18) | |
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | 8 | (3) | $ (31) |
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other income/(expense), net | |||
Impact of derivative activities recognized in earnings | |||
Total gain (loss) on derivatives recognized in net income | $ 13 | $ 30 |
Derivatives and Risk Manageme75
Derivatives and Risk Management Activities - Assets and Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative assets and liabilities | |||
Asset derivatives fair value | $ 90 | $ 108 | |
Liability derivatives fair value | (425) | (481) | |
Initial margin | 48 | 119 | |
Variation margin posted | 164 | 291 | |
Net broker receivable | 212 | 410 | |
Net loss deferred in AOCI | 223 | ||
Net loss expected to be reclassified to earnings in the next twelve months | 8 | ||
Remaining loss expected to be reclassified to earnings through 2049 | 215 | ||
Net deferred gain/(loss) recognized in AOCI on derivatives | (16) | (33) | $ 1 |
Commodity Derivatives | |||
Derivative assets and liabilities | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | 33 | ||
Interest Rate Derivatives | |||
Derivative assets and liabilities | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | (16) | (33) | $ (32) |
Derivatives in Hedging Relationships | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 2 | ||
Liability derivatives fair value | (38) | (50) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 2 | ||
Liability derivatives fair value | (27) | (23) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Liability derivatives fair value | (11) | (27) | |
Derivatives Not Designated as a Hedge | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 88 | 108 | |
Liability derivatives fair value | (387) | (431) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 73 | 101 | |
Liability derivatives fair value | (227) | (344) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 1 | 2 | |
Liability derivatives fair value | (1) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 5 | ||
Liability derivatives fair value | (131) | (14) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 3 | 2 | |
Liability derivatives fair value | (5) | (34) | |
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 6 | ||
Liability derivatives fair value | (2) | ||
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset derivatives fair value | 3 | ||
Liability derivatives fair value | (6) | ||
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Liability derivatives fair value | $ (22) | $ (32) |
Derivatives and Risk Manageme76
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Asset Positions | ||
Gross Position - Asset | $ 90 | $ 108 |
Netting Adjustment | (239) | (350) |
Cash collateral paid | 212 | 410 |
Net Position - Asset | 63 | 168 |
Derivative Liability Positions | ||
Gross Position - Liability | (425) | (481) |
Netting Adjustment | 239 | 350 |
Net Position - Liability | (186) | (131) |
Other current assets | ||
Derivative Asset Positions | ||
Net Position - Asset | 62 | 167 |
Other long-term assets, net | ||
Derivative Asset Positions | ||
Net Position - Asset | 1 | 1 |
Other current liabilities | ||
Derivative Liability Positions | ||
Net Position - Liability | (151) | (40) |
Other long-term liabilities and deferred credits | ||
Derivative Liability Positions | ||
Net Position - Liability | $ (35) | $ (91) |
Derivatives and Risk Manageme77
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Level 3 | ||
Rollforward of Level 3 Net Asset/(Liability) | ||
Beginning Balance | $ (36) | $ 11 |
Net gains for the period included in earnings | 12 | 28 |
Settlements | 4 | (10) |
Derivatives entered into during the period | (10) | (65) |
Ending Balance | (30) | (36) |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | 5 | (36) |
Recurring Fair Value Measures | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (335) | (373) |
Recurring Fair Value Measures | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (281) | (288) |
Recurring Fair Value Measures | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (36) | (50) |
Recurring Fair Value Measures | Foreign Currency Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | 4 | (3) |
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (22) | (32) |
Recurring Fair Value Measures | Level 1 | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | 5 | (113) |
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | 5 | (113) |
Recurring Fair Value Measures | Level 2 | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (310) | (224) |
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (278) | (171) |
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (36) | (50) |
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | 4 | (3) |
Recurring Fair Value Measures | Level 3 | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (30) | (36) |
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | (8) | (4) |
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | ||
Recurring Fair Value Measurements | ||
Net derivative asset/(liability) | $ (22) | $ (32) |
Income Taxes - Components (Det
Income Taxes - Components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current income tax expense: | |||
State income tax | $ 1 | $ 2 | $ 1 |
Canadian federal and provincial income tax | 27 | 83 | 83 |
Total current income tax expense | 28 | 85 | 84 |
Deferred income tax expense/(benefit): | |||
Canadian federal and provincial income tax | 16 | (60) | 16 |
Total deferred income tax expense/(benefit) | 16 | (60) | 16 |
Total income tax expense | $ 44 | $ 25 | $ 100 |
Income Taxes - Reconciliation
Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Examination [Line Items] | |||
Income before tax | $ 902 | $ 755 | $ 1,006 |
Partnership earnings not subject to current Canadian tax | (756) | (723) | (773) |
Partnership earnings subject to current Canadian tax | $ 146 | $ 32 | $ 233 |
Canadian federal and provincial corporate tax rate | 27.00% | 27.00% | 26.00% |
Income tax at statutory rate | $ 39 | $ 8 | $ 61 |
Canadian withholding tax | 2 | 13 | 14 |
Canadian permanent differences and rate changes | 2 | 2 | 24 |
State income tax | 1 | 2 | 1 |
Total income tax expense | 44 | 25 | $ 100 |
Deferred tax assets: | |||
Derivative instruments | 74 | 49 | |
Book accruals in excess of current tax deductions | 22 | 24 | |
Net operating losses | 3 | 4 | |
Total deferred tax assets | 99 | 77 | |
Deferred tax liabilities: | |||
Property and equipment in excess of tax values | (455) | (394) | |
Other | (50) | (41) | |
Total deferred tax liabilities | (505) | (435) | |
Net deferred tax liabilities | (406) | (358) | |
Other long-term assets, net | |||
Deferred tax liabilities: | |||
Net deferred tax assets | 3 | 4 | |
Other long-term liabilities and deferred credits | |||
Deferred tax liabilities: | |||
Net deferred tax liabilities | $ (409) | $ (362) |
Income Taxes - Operating Loss
Income Taxes - Operating Loss Carryforwards (Details) $ in Millions | Dec. 31, 2017USD ($) |
Foreign | |
Operating Loss Carryforwards | |
Net operating loss carryforwards | $ 9 |
Major Customers and Concentra81
Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Marathon Petroleum Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 19.00% | 18.00% | 17.00% |
ExxonMobil Corporation | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 11.00% | 14.00% | 13.00% |
Phillips 66 | |||
Major Customers and Concentration of Credit Risk | |||
Major customer percentage of total revenue | 11.00% | 11.00% |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Nov. 14, 2016 |
Related Party Transactions | ||||||
Limited partner interest | 98.00% | |||||
General Partner | ||||||
Related Party Transactions | ||||||
Costs reimbursed to general partner | $ 489 | $ 514 | $ 648 | |||
Oxy | ||||||
Related Party Transactions | ||||||
Revenues | 920 | 655 | 866 | |||
Purchases and related costs | (253) | 42 | 41 | |||
Trade accounts receivable and other receivables | $ 1,075 | 1,075 | 789 | |||
Accounts payable | 990 | 990 | 836 | |||
Equity Method Investees | ||||||
Related Party Transactions | ||||||
Revenues | 3 | 14 | 17 | |||
Trade accounts receivable and other receivables | 26 | 26 | 39 | |||
Accounts payable | $ 41 | 41 | 35 | |||
Costs related to services utilized | $ 434 | 209 | $ 164 | |||
Prepaid tariff costs | $ 14 | |||||
Equity Method Investees | Agreement to Transport Crude Oil | ||||||
Related Party Transactions | ||||||
Ownership interest | 50.00% | 50.00% | ||||
Class C Shares | PAGP | ||||||
Related Party Transactions | ||||||
Class C shares of PAGP held by PAA | 510,925,432 | 491,910,863 | ||||
Common Units | ||||||
Related Party Transactions | ||||||
Issuance of units (in units) | 54,119,893 | 22,133,904 | ||||
Omnibus Agreement | ||||||
Related Party Transactions | ||||||
Expenses paid on behalf of affiliates | $ 4 | $ 4 | ||||
AAP | ||||||
Related Party Transactions | ||||||
Limited partner interest | 36.00% | |||||
AAP | PAGP | ||||||
Related Party Transactions | ||||||
Limited partner interest | 55.00% | |||||
AAP | Oxy | ||||||
Related Party Transactions | ||||||
Limited partner interest | 11.00% | |||||
Continuous Offering Program | Common Units | ||||||
Related Party Transactions | ||||||
Issuance of units (in units) | 4,033,567 | 26,278,288 | 1,133,904 | |||
Continuous Offering Program | Omnibus Agreement | Common Units | AAP | ||||||
Related Party Transactions | ||||||
Issuance of units (in units) | 1,800,000 | |||||
Underwritten Offering | Common Units | ||||||
Related Party Transactions | ||||||
Issuance of units (in units) | 21,000,000 | |||||
Underwritten Offering | Omnibus Agreement | Common Units | AAP | ||||||
Related Party Transactions | ||||||
Issuance of units (in units) | 48,300,000 | 48,300,000 |
Equity-Indexed Compensation P83
Equity-Indexed Compensation Plans - Plan Information (Details) - shares shares in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
LTIP | ||||
Equity-Indexed Compensation Plans | ||||
Authorized grants (in units) | 25.2 | |||
Units outstanding (in units) | 7.3 | 8.9 | 6.9 | 7.3 |
Units outstanding that include DERs (in units) | 2.6 | |||
Plains All American 2013 Long-Term Incentive Plan | ||||
Equity-Indexed Compensation Plans | ||||
Authorized grants (in units) | 13.1 | |||
Plains All American PNG Successor Long-Term Incentive Plan | ||||
Equity-Indexed Compensation Plans | ||||
Authorized grants (in units) | 1.3 | |||
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan | ||||
Equity-Indexed Compensation Plans | ||||
Authorized grants (in units) | 10.8 |
Equity-Indexed Compensation P84
Equity-Indexed Compensation Plans - Liability and Activity (Details) - LTIP - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Outstanding (in units) | |||
Outstanding at beginning of period (in units) | 8.9 | 6.9 | 7.3 |
Granted (in units) | 0.9 | 4.5 | 2.1 |
Vested (in units) | (1.7) | (1.9) | (2.1) |
Modified (in units) | 0 | 0 | |
Cancelled or forfeited (in units) | (0.8) | (0.6) | (0.4) |
Outstanding at end of period (in units) | 7.3 | 8.9 | 6.9 |
Weighted Average Grant Date Fair Value per Unit | |||
Outstanding at beginning of period (in dollars per unit) | $ 29.62 | $ 41.23 | $ 41.45 |
Granted (in dollars per unit) | 23.52 | 23.38 | 28.76 |
Vested (in dollars per unit) | 42.12 | 45.91 | 28.91 |
Modified (in dollars per unit) | (6.04) | (8.21) | |
Cancelled or forfeited (in dollars per unit) | 26.99 | 37.19 | 44.56 |
Outstanding at end of period (in dollars per unit) | $ 24.68 | $ 29.62 | $ 41.23 |
Units issued in connection with the settlement of vested awards, net of tax withholding (in units) | 0.6 | 0.5 | 0.5 |
Units withheld for taxes (in units) | 0.2 | 0.3 | 0.3 |
Vested awards settled in cash (in units) | 0.9 | 1.1 | 1.3 |
Liability Awards | |||
Equity-Indexed Compensation Plans | |||
Accrued liability related to all outstanding LTIP awards and DERs | $ 27 | $ 38 | |
Short-term accrued liability related to all outstanding LTIP awards and DERs | 15 | 25 | |
Long-term accrued liability related to all outstanding LTIP awards and DERs | $ 12 | $ 13 |
Equity-Indexed Compensation P85
Equity-Indexed Compensation Plans - AAP Management Units (Details) - AAP Management Units | Dec. 31, 2017shares |
Equity-Indexed Compensation Plans | |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 0 |
Unearned units | 800,000 |
Conversion Of AAP Management Units Into AAP Units | |
Equity-Indexed Compensation Plans | |
Unit conversion ratio | 0.941 |
AAP | |
Equity-Indexed Compensation Plans | |
Equivalent distribution entitled to be received when earned (as a percent) | 94.10% |
AAP | |
Equity-Indexed Compensation Plans | |
Common units to be issued | 0.941 |
Equity-Indexed Compensation P86
Equity-Indexed Compensation Plans - Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Consolidated Equity-Indexed Compensation Plan Information | |||
Equity-indexed compensation expense | $ 41 | $ 60 | $ 27 |
LTIP unit-settled vestings | 16 | 24 | 37 |
LTIP cash-settled vestings | 25 | $ 28 | $ 66 |
Equity-Indexed Compensation Plan Fair Value Amortization | |||
2,018 | 42 | ||
2,019 | 21 | ||
2,020 | 9 | ||
2,021 | 2 | ||
2,022 | 1 | ||
Total | $ 75 |
Commitments and Contingencies
Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Leases, rights-of-way easements and other | |||
2,018 | $ 188 | ||
2,019 | 155 | ||
2,020 | 127 | ||
2,021 | 107 | ||
2,022 | 90 | ||
Thereafter | 363 | ||
Total | 1,030 | ||
Other commitments | |||
2,018 | 205 | ||
2,019 | 178 | ||
2,020 | 145 | ||
2,021 | 127 | ||
2,022 | 109 | ||
Thereafter | 299 | ||
Total | 1,063 | ||
Total | |||
2,018 | 393 | ||
2,019 | 333 | ||
2,020 | 272 | ||
2,021 | 234 | ||
2,022 | 199 | ||
Thereafter | 662 | ||
Total | 2,093 | ||
Lease expense | 207 | $ 198 | $ 164 |
Expenses associated with agreements | 197 | $ 157 | $ 85 |
Agreement to Transport Crude Oil | Equity Method Investees | |||
Other commitments | |||
Total | $ 760 | ||
Total | |||
Ownership interest | 50.00% |
Commitments and Contingencies88
Commitments and Contingencies - Legal, Environmental or Regulatory (Details) | May 16, 2016countemployee | Jan. 06, 2016occasion | Jan. 01, 2015bbl | May 31, 2015bbl | Dec. 31, 2017USD ($)count | Dec. 31, 2017USD ($)countlawsuit | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities | $ 162,000,000 | $ 162,000,000 | $ 147,000,000 | |||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 55,000,000 | 55,000,000 | 56,000,000 | |||||
Trade Accounts Receivable And Other Receivables | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 29,000,000 | 29,000,000 | 39,000,000 | |||||
Other long-term assets, net | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 26,000,000 | 26,000,000 | 17,000,000 | |||||
Accounts Payable and Accrued Liabilities | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities, short-term | 72,000,000 | 72,000,000 | 61,000,000 | |||||
Other long-term liabilities and deferred credits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities, long-term | 90,000,000 | 90,000,000 | $ 86,000,000 | |||||
Line 901 Incident | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities | 94,000,000 | 94,000,000 | ||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 47,000,000 | 47,000,000 | ||||||
Estimated size of release (in barrels) | bbl | 2,934 | |||||||
Estimated size of release to reach Pacific Ocean (in bbl) | bbl | 598 | |||||||
Fines or penalties assessed | 0 | 0 | ||||||
Aggregate total estimated costs | 335,000,000 | 335,000,000 | ||||||
Recoveries from insurance carriers | 174,000,000 | |||||||
Total release costs probable of recovery from insurance carriers | 220,000,000 | 220,000,000 | ||||||
Line 901 Incident | Trade Accounts Receivable And Other Receivables | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 22,000,000 | 22,000,000 | ||||||
Line 901 Incident | Accounts Payable and Accrued Liabilities | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities | $ 62,000,000 | $ 62,000,000 | ||||||
Line 901 Incident | May 2016 Indictment | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of employees charged in indictment | employee | 1 | |||||||
Total number of counts | count | 46 | 13 | 13 | |||||
Total number of counts dismissed | count | 33 | |||||||
Number of felony charges dismissed | count | 1 | |||||||
Number of misdemeanor charges relating to wildlife | count | 7 | |||||||
Number of counts related to the release of crude oil or reporting of the release | count | 6 | |||||||
Number of felony charges | count | 3 | |||||||
Line 901 Incident | Class Action Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 9 | |||||||
Number of cases administratively consolidated into a single proceeding | lawsuit | 6 | |||||||
Line 901 Incident | Securities Law Class Action Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 2 | |||||||
Line 901 Incident | Unitholder Derivative Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 4 | |||||||
Mesa To Basin Pipeline | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated size of release (in barrels) | bbl | 500 | |||||||
Mesa To Basin Pipeline | PHMSA | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of occasions of alleged failure to carry out damage prevention program and other procedures | occasion | 4 | |||||||
Fines or penalties assessed | $ 184,300 | |||||||
United States | Line 901 Incident | Unitholder Derivative Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 2 |
Quarterly Financial Data (Una89
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Total revenues | $ 7,605 | $ 5,873 | $ 6,078 | $ 6,667 | $ 5,952 | $ 5,170 | $ 4,950 | $ 4,111 | $ 26,223 | $ 20,182 | $ 23,152 |
Gross margin | 327 | 112 | 325 | 665 | 286 | 419 | 219 | 349 | 1,429 | 1,273 | |
Operating income | 261 | 44 | 257 | 591 | 218 | 349 | 146 | 282 | 1,153 | 994 | 1,262 |
Net income | 191 | 34 | 189 | 444 | 127 | 298 | 102 | 203 | 858 | 730 | 906 |
Net income attributable to PAA | $ 191 | $ 33 | $ 188 | $ 444 | $ 126 | $ 297 | $ 101 | $ 202 | $ 856 | $ 726 | $ 903 |
Cash distributions per common unit (in dollars per unit) | $ 0.30 | $ 0.55 | $ 0.55 | $ 0.55 | $ 0.55 | $ 0.70 | $ 0.70 | $ 0.70 | $ 1.95 | $ 2.65 | |
Common Units | |||||||||||
Basic net income/(loss) per common unit (in dollars per unit) | 0.19 | (0.01) | 0.21 | 0.59 | 0.14 | 0.40 | (0.20) | 0.07 | 0.96 | 0.43 | $ 0.78 |
Diluted net income/(loss) per common unit (in dollars per unit) | $ 0.19 | $ (0.01) | $ 0.21 | $ 0.58 | $ 0.14 | $ 0.40 | $ (0.20) | $ 0.07 | $ 0.95 | $ 0.43 | $ 0.77 |
Operating Segments - Segment F
Operating Segments - Segment Financial Data (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Operating Segments | |||||||||||
Operating segments number | segment | 3 | ||||||||||
Revenues: | |||||||||||
Revenues | $ 7,605 | $ 5,873 | $ 6,078 | $ 6,667 | $ 5,952 | $ 5,170 | $ 4,950 | $ 4,111 | $ 26,223 | $ 20,182 | $ 23,152 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||||||||
Equity earnings in unconsolidated entities | 290 | 195 | 183 | ||||||||
Segment adjusted EBITDA | 2,081 | 2,167 | 2,212 | ||||||||
Capital expenditures | 2,458 | 1,694 | 2,275 | ||||||||
Maintenance capital | 247 | 186 | 220 | ||||||||
Total assets | 25,351 | 24,210 | 25,351 | 24,210 | 22,288 | ||||||
Investments in unconsolidated entities | 2,756 | 2,343 | 2,756 | 2,343 | 2,027 | ||||||
Transportation | |||||||||||
Revenues: | |||||||||||
Revenues | 1,021 | 954 | 953 | ||||||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||||||||
Equity earnings in unconsolidated entities | 290 | 195 | 183 | ||||||||
Segment adjusted EBITDA | 1,287 | 1,141 | 1,056 | ||||||||
Capital expenditures | 2,126 | 1,063 | 1,278 | ||||||||
Maintenance capital | 120 | 121 | 144 | ||||||||
Total assets | 12,661 | 10,917 | 12,661 | 10,917 | 10,345 | ||||||
Investments in unconsolidated entities | 2,681 | 2,290 | 2,681 | 2,290 | 1,998 | ||||||
Facilities | |||||||||||
Revenues: | |||||||||||
Revenues | 555 | 546 | 528 | ||||||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||||||||
Segment adjusted EBITDA | 734 | 667 | 588 | ||||||||
Capital expenditures | 312 | 577 | 813 | ||||||||
Maintenance capital | 114 | 55 | 68 | ||||||||
Total assets | 7,313 | 7,556 | 7,313 | 7,556 | 7,330 | ||||||
Investments in unconsolidated entities | 75 | 53 | 75 | 53 | 29 | ||||||
Supply and Logistics | |||||||||||
Revenues: | |||||||||||
Revenues | 25,056 | 19,004 | 21,927 | ||||||||
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | |||||||||||
Segment adjusted EBITDA | 60 | 359 | 568 | ||||||||
Capital expenditures | 20 | 54 | 184 | ||||||||
Maintenance capital | 13 | 10 | 8 | ||||||||
Total assets | $ 5,377 | $ 5,737 | 5,377 | 5,737 | 4,613 | ||||||
Operating Segments | |||||||||||
Revenues: | |||||||||||
Revenues | 27,956 | 21,709 | 24,589 | ||||||||
Operating Segments | Transportation | |||||||||||
Revenues: | |||||||||||
Revenues | 1,718 | 1,584 | 1,594 | ||||||||
Operating Segments | Facilities | |||||||||||
Revenues: | |||||||||||
Revenues | 1,173 | 1,107 | 1,050 | ||||||||
Operating Segments | Supply and Logistics | |||||||||||
Revenues: | |||||||||||
Revenues | 25,065 | 19,018 | 21,945 | ||||||||
Intersegment | |||||||||||
Revenues: | |||||||||||
Revenues | (1,733) | (1,527) | (1,437) | ||||||||
Intersegment | Transportation | |||||||||||
Revenues: | |||||||||||
Revenues | (697) | (630) | (641) | ||||||||
Intersegment | Facilities | |||||||||||
Revenues: | |||||||||||
Revenues | (618) | (561) | (522) | ||||||||
Intersegment | Supply and Logistics | |||||||||||
Revenues: | |||||||||||
Revenues | (9) | (14) | (18) | ||||||||
Intersegment Adjustment | |||||||||||
Revenues: | |||||||||||
Revenues | $ (409) | $ (322) | $ (256) |
Operating Segments - Reconcili
Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | |||||||||||
Segment adjusted EBITDA | $ 2,081 | $ 2,167 | $ 2,212 | ||||||||
Adjustments: | |||||||||||
Depreciation and amortization of unconsolidated entities | (45) | (50) | (45) | ||||||||
Gains/(losses) from derivative activities net of inventory valuation adjustments | 46 | (404) | (110) | ||||||||
Long-term inventory costing adjustments | 24 | 58 | (99) | ||||||||
Deficiencies under minimum volume commitments, net | (2) | (46) | (13) | ||||||||
Equity-indexed compensation expense | (23) | (33) | (27) | ||||||||
Net gain/(loss) on foreign currency revaluation | 26 | (9) | 29 | ||||||||
Significant acquisition-related expenses | (6) | ||||||||||
Depreciation and amortization | (626) | (494) | (432) | ||||||||
Interest expense, net | (510) | (467) | (432) | ||||||||
Other income/(expense), net | (31) | 33 | (7) | ||||||||
INCOME BEFORE TAX | 902 | 755 | 1,006 | ||||||||
Income tax expense | (44) | (25) | (100) | ||||||||
NET INCOME | $ 191 | $ 34 | $ 189 | $ 444 | $ 127 | $ 298 | $ 102 | $ 203 | 858 | 730 | 906 |
Net income attributable to noncontrolling interests | (2) | (4) | (3) | ||||||||
NET INCOME ATTRIBUTABLE TO PAA | $ 191 | $ 33 | $ 188 | $ 444 | $ 126 | $ 297 | $ 101 | $ 202 | 856 | $ 726 | 903 |
Line 901 Incident | |||||||||||
Adjustments: | |||||||||||
Line 901 incident | $ (32) | $ (83) |
Operating Segments - Geographi
Operating Segments - Geographic Data (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Geographic Data | |||||||||||
Revenues | $ 7,605 | $ 5,873 | $ 6,078 | $ 6,667 | $ 5,952 | $ 5,170 | $ 4,950 | $ 4,111 | $ 26,223 | $ 20,182 | $ 23,152 |
Long-lived assets | 21,346 | 19,936 | 21,346 | 19,936 | |||||||
United States | |||||||||||
Geographic Data | |||||||||||
Revenues | 21,443 | 15,599 | 18,701 | ||||||||
Long-lived assets | 17,167 | 16,041 | 17,167 | 16,041 | |||||||
Canada | |||||||||||
Geographic Data | |||||||||||
Revenues | 4,780 | 4,583 | $ 4,451 | ||||||||
Long-lived assets | $ 4,179 | $ 3,895 | $ 4,179 | $ 3,895 |