Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | May 01, 2017 | |
Document and Entity Information | ||
Entity Registrant Name | PLAINS ALL AMERICAN PIPELINE LP | |
Entity Central Index Key | 1,070,423 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2017 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding (shares) | 724,657,263 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 38 | $ 47 |
Trade accounts receivable and other receivables, net | 2,218 | 2,279 |
Inventory | 1,219 | 1,343 |
Other current assets | 735 | 603 |
Total current assets | 4,210 | 4,272 |
PROPERTY AND EQUIPMENT | 16,468 | 16,220 |
Accumulated depreciation | (2,408) | (2,348) |
Property and equipment, net | 14,060 | 13,872 |
OTHER ASSETS | ||
Goodwill | 2,596 | 2,344 |
Investments in unconsolidated entities | 2,469 | 2,343 |
Linefill and base gas | 883 | 896 |
Long-term inventory | 131 | 193 |
Other long-term assets, net | 920 | 290 |
Total assets | 25,269 | 24,210 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 2,474 | 2,588 |
Short-term debt | 1,341 | 1,715 |
Other current liabilities | 341 | 361 |
Total current liabilities | 4,156 | 4,664 |
LONG-TERM LIABILITIES | ||
Senior notes, net of unamortized discounts and debt issuance costs | 9,876 | 9,874 |
Other long-term debt | 3 | 250 |
Other long-term liabilities and deferred credits | 644 | 606 |
Total long-term liabilities | 10,523 | 10,730 |
COMMITMENTS AND CONTINGENCIES (NOTE 12) | ||
PARTNERS’ CAPITAL | ||
Total partners’ capital excluding noncontrolling interests | 10,534 | 8,759 |
Noncontrolling interests | 56 | 57 |
Total partners’ capital | 10,590 | 8,816 |
Total liabilities and partners’ capital | 25,269 | 24,210 |
Series A Preferred Units | ||
PARTNERS’ CAPITAL | ||
Unitholders | 1,507 | 1,508 |
Common Units | ||
PARTNERS’ CAPITAL | ||
Unitholders | $ 9,027 | $ 7,251 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Mar. 31, 2017 | Dec. 31, 2016 |
Series A Preferred Units | ||
Units outstanding (units) | 65,676,626 | 64,388,853 |
Common Units | ||
Units outstanding (units) | 723,404,994 | 669,194,419 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
REVENUES | ||
Supply and Logistics segment revenues | $ 6,395 | $ 3,819 |
Transportation segment revenues | 138 | 154 |
Facilities segment revenues | 134 | 138 |
Total revenues | 6,667 | 4,111 |
COSTS AND EXPENSES | ||
Purchases and related costs | 5,593 | 3,348 |
Field operating costs | 288 | 300 |
General and administrative expenses | 74 | 67 |
Depreciation and amortization | 121 | 114 |
Total costs and expenses | 6,076 | 3,829 |
OPERATING INCOME | 591 | 282 |
OTHER INCOME/(EXPENSE) | ||
Equity earnings in unconsolidated entities | 53 | 47 |
Interest expense (net of capitalized interest of $6 and $13, respectively) | (129) | (112) |
Other income/(expense), net | (5) | 5 |
INCOME BEFORE TAX | 510 | 222 |
Current income tax expense | (10) | (31) |
Deferred income tax benefit/(expense) | (56) | 12 |
NET INCOME | 444 | 203 |
Net income attributable to noncontrolling interests | 0 | (1) |
NET INCOME ATTRIBUTABLE TO PAA | 444 | 202 |
NET INCOME PER COMMON UNIT (NOTE 3): | ||
Net income allocated to common unitholders - Basic | 406 | 28 |
Net income allocated to common unitholders - Diluted | $ 443 | $ 28 |
Common Units | ||
NET INCOME PER COMMON UNIT (NOTE 3): | ||
Basic weighted average common units outstanding (units) | 691 | 398 |
Basic net income per common unit (usd per unit) | $ 0.59 | $ 0.07 |
Diluted weighted average common units outstanding (units) | 758 | 399 |
Diluted net income per common unit (usd per unit) | $ 0.58 | $ 0.07 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Statement [Abstract] | ||
Interest expense, capitalized interest | $ 6 | $ 13 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Net income | $ 444 | $ 203 |
Other comprehensive income | 36 | 118 |
Comprehensive income | 480 | 321 |
Comprehensive income attributable to noncontrolling interests | (1) | |
Comprehensive income attributable to PAA | $ 480 | $ 320 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Changes in Accumulated Other Comprehensive Income/(Loss) | ||
Balance at beginning of period | $ (1,009) | $ (1,081) |
Reclassification adjustments | 2 | 1 |
Deferred gain (loss) on cash flow hedges | 7 | (90) |
Currency translation adjustments | 27 | 207 |
Total period activity | 36 | 118 |
Balance at end of period | (973) | (963) |
Derivative Instruments | ||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||
Balance at beginning of period | (228) | (203) |
Reclassification adjustments | 2 | 1 |
Deferred gain (loss) on cash flow hedges | 7 | (90) |
Total period activity | 9 | (89) |
Balance at end of period | (219) | (292) |
Translation Adjustments | ||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||
Balance at beginning of period | (782) | (878) |
Currency translation adjustments | 27 | 207 |
Total period activity | 27 | 207 |
Balance at end of period | (755) | $ (671) |
Other | ||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||
Balance at beginning of period | 1 | |
Balance at end of period | $ 1 |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income | $ 444 | $ 203 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation and amortization | 121 | 114 |
Equity-indexed compensation expense | 12 | 4 |
Deferred income tax (benefit)/expense | 56 | (12) |
(Gain)/loss on foreign currency revaluation | (3) | (3) |
Equity earnings in unconsolidated entities | (53) | (47) |
Distributions from unconsolidated entities | 52 | 52 |
Other | 10 | 6 |
Changes in assets and liabilities, net of acquisitions | 177 | 318 |
Net cash provided by operating activities | 816 | 635 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Cash paid in connection with acquisitions, net of cash acquired | (1,254) | (85) |
Investments in unconsolidated entities | (123) | (75) |
Additions to property, equipment and other | (275) | (372) |
Proceeds from sales of assets | 161 | 246 |
Other investing activities | (1) | |
Net cash used in investing activities | (1,491) | (287) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Net borrowings/(repayments) under commercial paper program (Note 8) | 149 | (1,211) |
Net repayments under senior secured hedged inventory facility (Note 8) | (501) | (300) |
Repayments of senior notes (Note 8) | (400) | |
Net proceeds from the sale of Series A preferred units | 1,570 | |
Net proceeds from the sale of common units (Note 9) | 1,664 | |
Contributions from general partner | 33 | |
Distributions paid to common unitholders (Note 9) | (371) | (278) |
Distributions paid to general partner | (155) | |
Other financing activities | 125 | (2) |
Net cash provided by/(used in) financing activities | 666 | (343) |
Effect of translation adjustment on cash | 4 | |
Net increase/(decrease) in cash and cash equivalents | (9) | 9 |
Cash and cash equivalents, beginning of period | 47 | 27 |
Cash and cash equivalents, end of period | 38 | 36 |
Cash paid for: | ||
Interest, net of amounts capitalized | 92 | 85 |
Income taxes, net of amounts refunded | $ 27 | $ 16 |
CONDENSED CONSOLIDATED STATEME9
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Total | Noncontrolling Interests | Partners’ Capital Excluding Noncontrolling Interests | Limited PartnersSeries A Preferred UnitsPartners’ Capital Excluding Noncontrolling Interests | Limited PartnersCommon UnitsPartners’ Capital Excluding Noncontrolling Interests | AAPPartners’ Capital Excluding Noncontrolling Interests |
Balance, beginning of period at Dec. 31, 2015 | $ 7,939 | $ 58 | $ 7,881 | $ 7,580 | $ 301 | |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 203 | 1 | 202 | 55 | 147 | |
Cash distributions to partners | (434) | (1) | (433) | (278) | (155) | |
Sale of Series A preferred units | 1,542 | 1,542 | $ 1,509 | 33 | ||
Other comprehensive income | 118 | 118 | 115 | 3 | ||
Other | 3 | 3 | 2 | 1 | ||
Balance, end of period at Mar. 31, 2016 | 9,371 | 58 | 9,313 | 1,509 | 7,474 | $ 330 |
Balance, beginning of period at Dec. 31, 2016 | 8,816 | 57 | 8,759 | 1,508 | 7,251 | |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 444 | 444 | 444 | |||
Cash distributions to partners | (372) | (1) | (371) | (371) | ||
Sales of common units | 1,664 | 1,664 | 1,664 | |||
Other comprehensive income | 36 | 36 | 36 | |||
Other | 2 | 2 | (1) | 3 | ||
Balance, end of period at Mar. 31, 2017 | $ 10,590 | $ 56 | $ 10,534 | $ 1,507 | $ 9,027 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 3 Months Ended |
Mar. 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-Q 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 for crude oil, natural gas liquids (“NGL”), natural gas and refined products. 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 13 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 March 31, 2017 , AAP also owned an approximate 37% limited partner interest in us represented by approximately 288.3 million of our common units. 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 March 31, 2017 , owned an approximate 53% 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”) that simplified our governance structure and permanently eliminated 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 common units and the assumption by us of all of AAP’s outstanding debt. See Note 1 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional discussion of the Simplification Transactions. Definitions Additional defined terms are used in this Form 10-Q 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 CODM = Chief Operating Decision Maker 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 LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet 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 SEC = United States Securities and Exchange Commission USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2016 Annual Report on Form 10-K. The accompanying condensed 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. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. 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. The condensed consolidated balance sheet data as of December 31, 2016 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2017 should not be taken as indicative of results to be expected for the entire year. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. |
Recent Accounting Pronouncement
Recent Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Except as discussed below and in our 2016 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2017 that are of significance or potential significance to us. Accounting Standards Updates Adopted During the Period 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 guidance was 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) will classify units directly withheld for tax-withholding purposes as a financing activity on our Condensed Consolidated Statement of Cash Flows for all periods presented. Our adoption did not have a material impact on our financial position, results of operations or cash flows for the periods presented. 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 annual periods beginning after December 15, 2019, and interim periods within those annual periods, with early adoption permitted. We early adopted this ASU in the first quarter of 2017, and the amendments therein will be applied prospectively to all future goodwill impairment tests performed on an interim or annual basis. Accounting Standards Updates Issued During the Period 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 becomes effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We plan to adopt this guidance on January 1, 2018 and will apply the new guidance to applicable transactions occurring after that date. 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 update includes the following clarifications: (i) nonfinancial assets within the scope of Subtopic 610-20 may include nonfinancial assets transferred within a legal entity to a counterparty, (ii) an entity should allocate consideration to each distinct asset by applying the guidance in Topic 606 on allocating the transaction price to performance obligations and (iii) requires entities to derecognize a distinct nonfinancial asset or distinct in substance nonfinancial asset in a partial sale transaction when it (1) does not have (or ceases to have) a controlling financial interest in the legal entity that holds the asset in accordance with Subtopic 810-10 and (2) transfers control of the asset in accordance with Topic 606. This guidance is effective beginning after December 15, 2017, including interim periods within those periods and must be adopted at the same time as ASC 606. We will adopt this guidance on January 1, 2018 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows. |
Net Income Per Common Unit
Net Income Per Common Unit | 3 Months Ended |
Mar. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income Per Common Unit | Net Income Per Common Unit 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. 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. Diluted net income per common unit 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) units that are issuable to AAP when certain AAP Management Units are earned. 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 three months ended March 31, 2016 as the effect was antidilutive. Our LTIP awards and certain AAP Management Units that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs 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 are 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 March 31, 2017, no units issuable to AAP were contemplated in the calculation of diluted net income per common unit. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs. The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Three Months Ended 2017 2016 Basic Net Income per Common Unit Net income attributable to PAA $ 444 $ 202 Distributions to Series A preferred units (1) (34 ) (23 ) Distributions to general partner (1) — (155 ) Distributions to participating securities (1) (1 ) (1 ) Undistributed loss allocated to general partner (1) — 5 Other (3 ) — Net income allocated to common unitholders $ 406 $ 28 Basic weighted average common units outstanding 691 398 Basic net income per common unit $ 0.59 $ 0.07 Diluted Net Income per Common Unit Net income attributable to PAA $ 444 $ 202 Distributions to Series A preferred units (1) — (23 ) Distributions to general partner (1) — (155 ) Distributions to participating securities (1) (1 ) (1 ) Undistributed loss allocated to general partner (1) — 5 Net income allocated to common unitholders $ 443 $ 28 Basic weighted average common units outstanding 691 398 Effect of dilutive securities: Series A preferred units 65 — LTIP units 2 1 Diluted weighted average common units outstanding 758 399 Diluted net income per common unit $ 0.58 $ 0.07 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. 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, 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. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions or allocations on these interests. |
Accounts Receivable, Net
Accounts Receivable, Net | 3 Months Ended |
Mar. 31, 2017 | |
Receivables [Abstract] | |
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. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions 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 or parental guarantees. As of March 31, 2017 and December 31, 2016 , we had received $81 million and $89 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $46 million and $66 million as of March 31, 2017 and December 31, 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 a majority of such 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 March 31, 2017 and December 31, 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 March 31, 2017 and December 31, 2016 . Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. |
Inventory, Linefill and Base Ga
Inventory, Linefill and Base Gas and Long-term Inventory | 3 Months Ended |
Mar. 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, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): March 31, 2017 December 31, 2016 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil 21,710 barrels $ 1,071 $ 49.33 23,589 barrels $ 1,049 $ 44.47 NGL 5,396 barrels 120 $ 22.24 13,497 barrels 242 $ 17.93 Natural gas 3,630 Mcf 10 $ 2.75 14,540 Mcf 32 $ 2.20 Other N/A 18 N/A N/A 20 N/A Inventory subtotal 1,219 1,343 Linefill and base gas Crude oil 12,679 barrels 729 $ 57.50 12,273 barrels 710 $ 57.85 NGL 1,646 barrels 46 $ 27.95 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 883 896 Long-term inventory Crude oil 2,345 barrels 101 $ 43.07 3,279 barrels 163 $ 49.71 NGL 1,418 barrels 30 $ 21.16 1,418 barrels 30 $ 21.16 Long-term inventory subtotal 131 193 Total $ 2,233 $ 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. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 3 Months Ended |
Mar. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | Acquisitions and Dispositions Acquisitions The following acquisitions 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. 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 $1.217 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 9 for additional information. Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises 515 miles of gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink. We intend to make additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements intended 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, and include 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 determination of the acquisition-date fair value of the assets acquired and liabilities assumed is preliminary. We expect to finalize our fair value determination in 2017. The following table reflects the preliminary 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 20 641 Goodwill N/A 278 Other (including $4 million of cash acquired) N/A (1 ) $ 1,217 Intangible assets are included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. The preliminary 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 was approximately $1 million for the period ended March 31, 2017, and the future amortization is estimated as follows for the next five years (in millions): Remainder of 2017 $ 9 2018 $ 25 2019 $ 34 2020 $ 42 2021 $ 48 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 three months ended March 31, 2017, we incurred approximately $5 million of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of general and administrative expenses in our Condensed Consolidated Statement 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, 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. Investment 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”) 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 and approximately $26 million in cash. Advantage owns a 70 -mile, 16 -inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”). Noble will serve as operator and will construct a pipeline to deliver crude oil to the Advantage Pipeline from its central gathering facility in the southern Delaware Basin. We will construct a pipeline to connect our Wolfbone Ranch facility to the Advantage Pipeline near Highway 285 in Reeves County, Texas. The connections are estimated to be completed in 2017. The Advantage Pipeline is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Dispositions and Divestitures During the three months ended March 31, 2017, we sold certain non-core assets for proceeds of approximately $161 million . These sales primarily included (i) a non-core pipeline segment located in the Midwestern United States and (ii) a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma (the “Hewitt Segment”) for our net book value. We retained a 60% undivided interest in the Hewitt Segment and a 100% interest in the remaining portion of the Red River Pipeline that extends from Ardmore to Longview, Texas. We recognized a net gain of $36 million related to the sale of the non-core pipeline segment, including the write-off of a portion of the remaining book value, which is included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. Assets Held for Sale As of March 31, 2017, we classified approximately $490 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) primarily related to definitive agreements to sell non-core assets, including certain of our West Coast terminal assets and our Bluewater natural gas storage facility located in Michigan. The assets held for sale are primarily property and equipment and are included in our Facilities segment. We expect these transactions to close in the second quarter or early in the third quarter of 2017, subject to customary closing conditions, including the receipt of regulatory approvals. During the three months ended March 31, 2017, we recognized an impairment loss of $31 million related to assets held for sale. This impairment loss is included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. |
Goodwill
Goodwill | 3 Months Ended |
Mar. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill Goodwill by segment and changes in goodwill are reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344 Acquisitions (1) 278 — — 278 Foreign currency translation adjustments 2 1 — 3 Dispositions and reclassifications to assets held for sale — (29 ) — (29 ) Balance at March 31, 2017 $ 1,086 $ 1,006 $ 504 $ 2,596 (1) Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Debt Debt consisted of the following (in millions): March 31, December 31, 2016 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 1.9% and 1.6%, respectively (1) $ 958 $ 563 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.0% and 1.8%, respectively (1) 250 750 Senior notes: 6.13% senior notes due January 2017 — 400 Other 133 2 Total short-term debt (2) 1,341 1,715 LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $74 and $76, respectively 9,876 9,874 Commercial paper notes, bearing a weighted-average interest rate of 1.6% (3) — 247 Other 3 3 Total long-term debt 9,879 10,124 Total debt (4) $ 11,220 $ 11,839 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2017 and December 31, 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 March 31, 2017 and December 31, 2016 , balance includes borrowings of $95 million and $410 million , respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) At December 31, 2016 , we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis. (4) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.9 billion and $ 10.3 billion as of March 31, 2017 and December 31, 2016 , respectively. We estimated the aggregate fair value of these notes as of March 31, 2017 and December 31, 2016 to be approximately $10.1 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 the end of the reporting period. 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. Borrowings and Repayments Total borrowings under our credit facilities and commercial paper program for the three months ended March 31, 2017 and 2016 were approximately $18.8 billion and $10.8 billion , respectively. Total repayments under our credit facilities and commercial paper program were approximately $19.2 billion and $12.3 billion for the three months ended March 31, 2017 and 2016 , 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 of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At March 31, 2017 and December 31, 2016 , we had outstanding letters of credit of $77 million and $73 million , respectively. Senior Notes Repayments Our $400 million , 6.13% senior notes were repaid in January 2017. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes. |
Partners' Capital and Distribut
Partners' Capital and Distributions | 3 Months Ended |
Mar. 31, 2017 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Units Outstanding The following tables present the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2016 64,388,853 669,194,419 Issuance of Series A preferred units in connection with in-kind distributions 1,287,773 — Sales of common units — 54,119,893 Issuance of common units under LTIP — 90,682 Outstanding at March 31, 2017 65,676,626 723,404,994 Limited Partners Preferred Units Common Units Outstanding at December 31, 2015 — 397,727,624 Sale of Series A preferred units 61,030,127 — Issuance of common units under LTIP — 3,367 Outstanding at March 31, 2016 61,030,127 397,730,991 Sales of Common Units The following table summarizes our sales of common units during the three months ended March 31, 2017 (net proceeds in millions): Type of Offering Common Units Issued Net Proceeds (1) Continuous Offering Program 4,033,567 $ 129 (2 ) Omnibus Agreement (3) 50,086,326 (4 ) 1,535 54,119,893 $ 1,664 (1) Amounts are net of costs associated with the offerings. (2) We pay commissions to our sales agents in connection with common units issuances under our Continuous Offering Program. We paid $1 million of such commissions during the three months ended March 31, 2017. (3) Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, PAGP has agreed to use the net proceeds from any public or private offering and sale of 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 Class A shares sold in such offering at a price equal to the net proceeds from such offering. The Omnibus Agreement also provides that immediately following such purchase and sale, AAP will use the net proceeds it receives from such sale of AAP units to purchase from us an equivalent number of our common units. (4) 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. Distributions Cash Distributions . The following table details the distributions paid in cash during or pertaining to the first three months of 2017 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP May 15, 2017 (1) $ 240 $ 159 $ 399 $ 0.55 February 14, 2017 $ 237 $ 134 $ 371 $ 0.55 (1) Payable to unitholders of record at the close of business on May 1, 2017 for the period January 1, 2017 through March 31, 2017 . In-Kind Distributions . On February 14, 2017, we issued 1,287,773 Series A preferred units in lieu of a cash distribution of $34 million on our Series A preferred units outstanding as of the record date for such distribution. On May 15, 2017, we will issue 1,313,527 Series A preferred units in lieu of a cash distribution of $34 million on our Series A preferred units outstanding as of the record date for such distribution. Since the May 15, 2017 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of March 31, 2017 and thus had no net impact on the Series A preferred unitholders’ capital account. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 3 Months Ended |
Mar. 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 March 31, 2017 , net derivative positions related to these activities included: • A net long position of 2.6 million barrels associated with our crude oil purchases, which was unwound ratably during April 2017 to match monthly average pricing. • A net short time spread position of 4.6 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through July 2018. • A crude oil grade basis position of 42.1 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials. • A net short position of 3.5 Bcf through April 2017 related to anticipated sales of natural gas inventory. • A net short position of 24.0 million barrels through December 2019 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 loss allowance oil that is to be collected under our tariffs. As of March 31, 2017 , our PLA hedges included a long call option position of 0.8 million barrels through December 2018. 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 March 31, 2017 , we had a long natural gas position of 56.7 Bcf which hedges our natural gas processing and operational needs through December 2018. We also had a short propane position of 10.1 million barrels through December 2018, a short butane position of 3.1 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 2018. 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 risk associated with 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 payments associated with the underlying debt. The following table summarizes the terms of our outstanding interest derivatives as of March 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 8 forward starting swaps (30-year) $ 200 6/15/2017 3.14 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2018 3.20 % 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 and, at times, a portion of our debt is denominated 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 March 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 March 31, 2017 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2017 $ 175 $ 234 $1.00 - $1.34 Forward exchange contracts that exchange USD for CAD: 2017 $ 428 $ 569 $1.00 - $1.33 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 Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At March 31, 2017 , the fair value of this embedded derivative was a liability of approximately $36 million . We recognized a loss of approximately $4 million during the three months ended March 31, 2017 . See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional information regarding 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 Condensed Consolidated Statements of Cash Flows. A summary of the impact of our derivative activities recognized in earnings is as follows (in millions): Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships Derivatives Not Designated as a Hedge Total Derivatives in Hedging Relationships Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ — $ 96 $ 96 $ 1 $ 31 $ 32 Transportation segment revenues — — — — 2 2 Field operating costs — (3 ) (3 ) — (2 ) (2 ) Interest Rate Derivatives Interest expense, net (2 ) — (2 ) (2 ) — (2 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 2 2 — 6 6 Preferred Distribution Rate Reset Option Other income/(expense), net — (4 ) (4 ) — — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ (2 ) $ 91 $ 89 $ (1 ) $ 37 $ 36 The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives $ — Other current assets $ — Interest rate derivatives — Other current liabilities (20 ) Other long-term liabilities and deferred credits (23 ) Total derivatives designated as hedging instruments $ — $ (43 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 79 Other current assets $ (81 ) Other long-term assets, net 13 Other long-term assets, net (8 ) Other current liabilities 2 Other current liabilities (7 ) Other long-term liabilities and deferred credits (4 ) Foreign currency derivatives Other current assets 1 Other current liabilities (4 ) Other current liabilities 1 Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (36 ) Total derivatives not designated as hedging instruments $ 96 $ (140 ) Total derivatives $ 96 $ (183 ) The following table summarizes the derivative assets and liabilities on our Condensed 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: Commodity derivatives $ — Other current assets $ — 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 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): March 31, December 31, 2016 Initial margin $ 92 $ 119 Variation margin posted/(returned) 3 291 Net broker receivable/(payable) $ 95 $ 410 The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): March 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 96 $ (183 ) $ 108 $ (481 ) Netting adjustment (92 ) 92 (350 ) 350 Cash collateral paid/(received) 95 — 410 — Net position - asset/(liability) $ 99 $ (91 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 94 $ — $ 167 $ — Other long-term assets, net 5 — 1 — Other current liabilities — (28 ) — (40 ) Other long-term liabilities and deferred credits — (63 ) — (91 ) $ 99 $ (91 ) $ 168 $ (131 ) As of March 31, 2017 , there was a net loss of $219 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 March 31, 2017 , we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The remaining deferred loss of $211 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of March 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): Three Months Ended 2017 2016 Interest rate derivatives, net $ 7 $ (90 ) At March 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 March 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 $ (6 ) $ — $ — $ (6 ) $ (113 ) $ (171 ) $ (4 ) $ (288 ) Interest rate derivatives — (43 ) — (43 ) — (50 ) — (50 ) Foreign currency derivatives — (2 ) — (2 ) — (3 ) — (3 ) Preferred Distribution Rate Reset Option — — (36 ) (36 ) — — (32 ) (32 ) Total net derivative asset/(liability) $ (6 ) $ (45 ) $ (36 ) $ (87 ) $ (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 broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices 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 Condensed 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 Condensed 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): Three Months Ended 2017 2016 Beginning Balance $ (36 ) $ 11 Net losses for the period included in earnings (3 ) (1 ) Settlements 3 (9 ) Derivatives entered into during the period — (60 ) Ending Balance $ (36 ) $ (59 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (2 ) $ (1 ) |
Related Party Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions See Note 15 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a complete discussion of our related party transactions. Omnibus Agreement Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, we issued approximately 1.8 million units to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and 48.3 million units to AAP in connection with PAGP’s March 2017 underwritten offering. See Note 9 for additional information. Transactions with Oxy As of March 31, 2017 , Oxy had a representative on the board of directors of PAGP GP and owned approximately 10% of the limited partner interests in AAP. During the three months ended March 31, 2017 and 2016 , 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 Condensed Consolidated Statements of Operations from those transactions is included below (in millions): Three Months Ended 2017 2016 Revenues $ 234 $ 112 Purchases and related costs (1) $ (40 ) $ (46 ) (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed 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): March 31, December 31, 2016 Trade accounts receivable and other receivables $ 872 $ 789 Accounts payable $ 818 $ 836 |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies 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 March 31, 2017 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $139 million , of which $59 million was classified as short-term and $80 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 Condensed Consolidated Balance Sheets. At March 31, 2017 , we had recorded receivables totaling $47 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $34 million was reflected in “Trade accounts receivable and other receivables, net” and $13 million was reflected in “Other long-term assets, net” on our Condensed 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 Condensed 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 includes 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 also obligates 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 imposes a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and requires 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. 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. To date, PHMSA has not issued a final order with respect to the 2013 Audit NOPV, nor has it assessed any fines or penalties with respect thereto; however, we cannot provide any assurances that any such fines or penalties will not be assessed against us. 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 indictment included a total of 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts (currently three felony and seven misdemeanor charges) relate to the release of crude oil or reporting of the release. PAA believes that the criminal 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 intends to continue to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. 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 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 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, including potential classes such as commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or from persons or businesses who resold commercial seafood landed in such areas, retail businesses located in and around Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. To date, only the commercial fisherman and seafood reseller class has been certified by the court. 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 may appeal or refile. 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 these lawsuits; 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. 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 two remaining lawsuits 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 these lawsuits 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 these lawsuits. We have also had two lawsuits filed against us wherein the respective plaintiffs seek to compel the production of certain books and records that purportedly relate to the Line 901 incident, our alleged failure to comply with certain regulations and other matters. These lawsuits have been consolidated into a single proceeding in the Chancery Court for the State of Delaware. 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 March 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 $280 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” primarily during 2015. 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 March 31, 2017 , we had a remaining undiscounted gross liability of $68 million related to this event, of which approximately $48 million is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed 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 March 31, 2017 , we had collected, subject to customary reservations, $156 million out of the approximate $197 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of March 31, 2017 , we have recognized a receivable of approximately $41 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 $29 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed 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. In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. 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 . |
Operating Segments
Operating Segments | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Operating Segments | Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. 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 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 the 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 of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The following tables reflect certain financial data for each segment (in millions): Three Months Ended March 31, 2017 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Revenues: External customers $ 225 $ 134 $ 6,395 $ (87 ) $ 6,667 Intersegment (2) 164 159 5 87 415 Total revenues of reportable segments $ 389 $ 293 $ 6,400 $ — $ 7,082 Equity earnings in unconsolidated entities $ 53 $ — $ — $ 53 Segment adjusted EBITDA $ 273 $ 188 $ 51 $ 512 Maintenance capital $ 29 $ 27 $ 3 $ 59 Three Months Ended March 31, 2016 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Revenues: External customers $ 241 $ 138 $ 3,819 $ (87 ) $ 4,111 Intersegment (2) 142 127 2 87 358 Total revenues of reportable segments $ 383 $ 265 $ 3,821 $ — $ 4,469 Equity earnings in unconsolidated entities $ 47 $ — $ — $ 47 Segment adjusted EBITDA $ 281 $ 167 $ 184 $ 632 Maintenance capital $ 35 $ 9 $ 3 $ 47 (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 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K 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 Condensed 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 Condensed 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 at the time the agreement is executed or renegotiated. Segment Adjusted EBITDA Reconciliation The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Three Months Ended 2017 2016 Segment adjusted EBITDA $ 512 $ 632 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (14 ) (12 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 289 (122 ) Long-term inventory costing adjustments (4) (7 ) (23 ) Deficiencies under minimum volume commitments, net (5) (11 ) (27 ) Equity-indexed compensation expense (6) (3 ) (4 ) Net gain/(loss) on foreign currency revaluation (7) 4 (1 ) Significant acquisition-related expenses (8) (5 ) — Depreciation and amortization (121 ) (114 ) Interest expense, net (129 ) (112 ) Other income/(expense), net (5 ) 5 Income before tax 510 222 Income tax expense (66 ) (19 ) Net income 444 203 Net income attributable to noncontrolling interests — (1 ) Net income attributable to PAA $ 444 $ 202 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization 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. (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 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 three months ended March 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 period were not significant to segment adjusted EBITDA. |
Net Income Per Common Unit (Tab
Net Income Per Common Unit (Tables) | 3 Months Ended |
Mar. 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): Three Months Ended 2017 2016 Basic Net Income per Common Unit Net income attributable to PAA $ 444 $ 202 Distributions to Series A preferred units (1) (34 ) (23 ) Distributions to general partner (1) — (155 ) Distributions to participating securities (1) (1 ) (1 ) Undistributed loss allocated to general partner (1) — 5 Other (3 ) — Net income allocated to common unitholders $ 406 $ 28 Basic weighted average common units outstanding 691 398 Basic net income per common unit $ 0.59 $ 0.07 Diluted Net Income per Common Unit Net income attributable to PAA $ 444 $ 202 Distributions to Series A preferred units (1) — (23 ) Distributions to general partner (1) — (155 ) Distributions to participating securities (1) (1 ) (1 ) Undistributed loss allocated to general partner (1) — 5 Net income allocated to common unitholders $ 443 $ 28 Basic weighted average common units outstanding 691 398 Effect of dilutive securities: Series A preferred units 65 — LTIP units 2 1 Diluted weighted average common units outstanding 758 399 Diluted net income per common unit $ 0.58 $ 0.07 (1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. 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, 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. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions or allocations on these interests. |
Inventory, Linefill and Base 24
Inventory, Linefill and Base Gas and Long-term Inventory (Tables) | 3 Months Ended |
Mar. 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): March 31, 2017 December 31, 2016 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil 21,710 barrels $ 1,071 $ 49.33 23,589 barrels $ 1,049 $ 44.47 NGL 5,396 barrels 120 $ 22.24 13,497 barrels 242 $ 17.93 Natural gas 3,630 Mcf 10 $ 2.75 14,540 Mcf 32 $ 2.20 Other N/A 18 N/A N/A 20 N/A Inventory subtotal 1,219 1,343 Linefill and base gas Crude oil 12,679 barrels 729 $ 57.50 12,273 barrels 710 $ 57.85 NGL 1,646 barrels 46 $ 27.95 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 883 896 Long-term inventory Crude oil 2,345 barrels 101 $ 43.07 3,279 barrels 163 $ 49.71 NGL 1,418 barrels 30 $ 21.16 1,418 barrels 30 $ 21.16 Long-term inventory subtotal 131 193 Total $ 2,233 $ 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. |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule of assets acquired and liabilities assumed | The following table reflects the preliminary 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 20 641 Goodwill N/A 278 Other (including $4 million of cash acquired) N/A (1 ) $ 1,217 |
Schedule of finite lived intangible assets amortization expense | Amortization was approximately $1 million for the period ended March 31, 2017, and the future amortization is estimated as follows for the next five years (in millions): Remainder of 2017 $ 9 2018 $ 25 2019 $ 34 2020 $ 42 2021 $ 48 |
Goodwill (Tables)
Goodwill (Tables) | 3 Months Ended |
Mar. 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 are reflected in the following table (in millions): Transportation Facilities Supply and Logistics Total Balance at December 31, 2016 $ 806 $ 1,034 $ 504 $ 2,344 Acquisitions (1) 278 — — 278 Foreign currency translation adjustments 2 1 — 3 Dispositions and reclassifications to assets held for sale — (29 ) — (29 ) Balance at March 31, 2017 $ 1,086 $ 1,006 $ 504 $ 2,596 (1) Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized. |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consisted of the following (in millions): March 31, December 31, 2016 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 1.9% and 1.6%, respectively (1) $ 958 $ 563 Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.0% and 1.8%, respectively (1) 250 750 Senior notes: 6.13% senior notes due January 2017 — 400 Other 133 2 Total short-term debt (2) 1,341 1,715 LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $74 and $76, respectively 9,876 9,874 Commercial paper notes, bearing a weighted-average interest rate of 1.6% (3) — 247 Other 3 3 Total long-term debt 9,879 10,124 Total debt (4) $ 11,220 $ 11,839 (1) We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2017 and December 31, 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 March 31, 2017 and December 31, 2016 , balance includes borrowings of $95 million and $410 million , respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) At December 31, 2016 , we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis. (4) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.9 billion and $ 10.3 billion as of March 31, 2017 and December 31, 2016 , respectively. We estimated the aggregate fair value of these notes as of March 31, 2017 and December 31, 2016 to be approximately $10.1 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 the end of the reporting period. 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. |
Partners' Capital and Distrib28
Partners' Capital and Distributions (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Partners' Capital Notes [Abstract] | |
Schedule of activity for Series A preferred units and common units | The following tables present the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2016 64,388,853 669,194,419 Issuance of Series A preferred units in connection with in-kind distributions 1,287,773 — Sales of common units — 54,119,893 Issuance of common units under LTIP — 90,682 Outstanding at March 31, 2017 65,676,626 723,404,994 Limited Partners Preferred Units Common Units Outstanding at December 31, 2015 — 397,727,624 Sale of Series A preferred units 61,030,127 — Issuance of common units under LTIP — 3,367 Outstanding at March 31, 2016 61,030,127 397,730,991 |
Schedule of sale of common units | The following table summarizes our sales of common units during the three months ended March 31, 2017 (net proceeds in millions): Type of Offering Common Units Issued Net Proceeds (1) Continuous Offering Program 4,033,567 $ 129 (2 ) Omnibus Agreement (3) 50,086,326 (4 ) 1,535 54,119,893 $ 1,664 (1) Amounts are net of costs associated with the offerings. (2) We pay commissions to our sales agents in connection with common units issuances under our Continuous Offering Program. We paid $1 million of such commissions during the three months ended March 31, 2017. (3) Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, PAGP has agreed to use the net proceeds from any public or private offering and sale of 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 Class A shares sold in such offering at a price equal to the net proceeds from such offering. The Omnibus Agreement also provides that immediately following such purchase and sale, AAP will use the net proceeds it receives from such sale of AAP units to purchase from us an equivalent number of our common units. (4) 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 cash distributions to common unitholders | The following table details the distributions paid in cash during or pertaining to the first three months of 2017 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP May 15, 2017 (1) $ 240 $ 159 $ 399 $ 0.55 February 14, 2017 $ 237 $ 134 $ 371 $ 0.55 (1) Payable to unitholders of record at the close of business on May 1, 2017 for the period January 1, 2017 through March 31, 2017 . |
Derivatives and Risk Manageme29
Derivatives and Risk Management Activities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Derivatives and Risk Management Activities | |
Impact of derivative activities recognized in earnings | A summary of the impact of our derivative activities recognized in earnings is as follows (in millions): Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Location of Gain/(Loss) Derivatives in Hedging Relationships Derivatives Not Designated as a Hedge Total Derivatives in Hedging Relationships Derivatives Not Designated as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ — $ 96 $ 96 $ 1 $ 31 $ 32 Transportation segment revenues — — — — 2 2 Field operating costs — (3 ) (3 ) — (2 ) (2 ) Interest Rate Derivatives Interest expense, net (2 ) — (2 ) (2 ) — (2 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 2 2 — 6 6 Preferred Distribution Rate Reset Option Other income/(expense), net — (4 ) (4 ) — — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ (2 ) $ 91 $ 89 $ (1 ) $ 37 $ 36 |
Summary of derivative assets and liabilities on Condensed Consolidated Balance Sheets on a gross basis | The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives $ — Other current assets $ — Interest rate derivatives — Other current liabilities (20 ) Other long-term liabilities and deferred credits (23 ) Total derivatives designated as hedging instruments $ — $ (43 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 79 Other current assets $ (81 ) Other long-term assets, net 13 Other long-term assets, net (8 ) Other current liabilities 2 Other current liabilities (7 ) Other long-term liabilities and deferred credits (4 ) Foreign currency derivatives Other current assets 1 Other current liabilities (4 ) Other current liabilities 1 Preferred Distribution Rate Reset Option — Other long-term liabilities and deferred credits (36 ) Total derivatives not designated as hedging instruments $ 96 $ (140 ) Total derivatives $ 96 $ (183 ) The following table summarizes the derivative assets and liabilities on our Condensed 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: Commodity derivatives $ — Other current assets $ — 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 broker receivables and payables | The following table provides the components of our net broker receivable/(payable): March 31, December 31, 2016 Initial margin $ 92 $ 119 Variation margin posted/(returned) 3 291 Net broker receivable/(payable) $ 95 $ 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): March 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 96 $ (183 ) $ 108 $ (481 ) Netting adjustment (92 ) 92 (350 ) 350 Cash collateral paid/(received) 95 — 410 — Net position - asset/(liability) $ 99 $ (91 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 94 $ — $ 167 $ — Other long-term assets, net 5 — 1 — Other current liabilities — (28 ) — (40 ) Other long-term liabilities and deferred credits — (63 ) — (91 ) $ 99 $ (91 ) $ 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): March 31, 2017 December 31, 2016 Derivative Asset Positions Derivative Liability Positions Derivative Asset Positions Derivative Liability Positions Netting Adjustments: Gross position - asset/(liability) $ 96 $ (183 ) $ 108 $ (481 ) Netting adjustment (92 ) 92 (350 ) 350 Cash collateral paid/(received) 95 — 410 — Net position - asset/(liability) $ 99 $ (91 ) $ 168 $ (131 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 94 $ — $ 167 $ — Other long-term assets, net 5 — 1 — Other current liabilities — (28 ) — (40 ) Other long-term liabilities and deferred credits — (63 ) — (91 ) $ 99 $ (91 ) $ 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): Three Months Ended 2017 2016 Interest rate derivatives, net $ 7 $ (90 ) |
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 March 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 $ (6 ) $ — $ — $ (6 ) $ (113 ) $ (171 ) $ (4 ) $ (288 ) Interest rate derivatives — (43 ) — (43 ) — (50 ) — (50 ) Foreign currency derivatives — (2 ) — (2 ) — (3 ) — (3 ) Preferred Distribution Rate Reset Option — — (36 ) (36 ) — — (32 ) (32 ) Total net derivative asset/(liability) $ (6 ) $ (45 ) $ (36 ) $ (87 ) $ (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): Three Months Ended 2017 2016 Beginning Balance $ (36 ) $ 11 Net losses for the period included in earnings (3 ) (1 ) Settlements 3 (9 ) Derivatives entered into during the period — (60 ) Ending Balance $ (36 ) $ (59 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (2 ) $ (1 ) |
Interest Rate Swaps | |
Derivatives and Risk Management Activities | |
Schedule of terms of outstanding interest rate derivatives | The following table summarizes the terms of our outstanding interest derivatives as of March 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 8 forward starting swaps (30-year) $ 200 6/15/2017 3.14 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/15/2018 3.20 % 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 March 31, 2017 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2017 $ 175 $ 234 $1.00 - $1.34 Forward exchange contracts that exchange USD for CAD: 2017 $ 428 $ 569 $1.00 - $1.33 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Oxy | |
Related Party Transaction [Line Items] | |
Schedule of related party transactions | The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions): Three Months Ended 2017 2016 Revenues $ 234 $ 112 Purchases and related costs (1) $ (40 ) $ (46 ) (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed 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): March 31, December 31, 2016 Trade accounts receivable and other receivables $ 872 $ 789 Accounts payable $ 818 $ 836 |
Operating Segments (Tables)
Operating Segments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment financial data | The following tables reflect certain financial data for each segment (in millions): Three Months Ended March 31, 2017 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Revenues: External customers $ 225 $ 134 $ 6,395 $ (87 ) $ 6,667 Intersegment (2) 164 159 5 87 415 Total revenues of reportable segments $ 389 $ 293 $ 6,400 $ — $ 7,082 Equity earnings in unconsolidated entities $ 53 $ — $ — $ 53 Segment adjusted EBITDA $ 273 $ 188 $ 51 $ 512 Maintenance capital $ 29 $ 27 $ 3 $ 59 Three Months Ended March 31, 2016 Transportation Facilities Supply and Logistics Intersegment Adjustment (1) Total Revenues: External customers $ 241 $ 138 $ 3,819 $ (87 ) $ 4,111 Intersegment (2) 142 127 2 87 358 Total revenues of reportable segments $ 383 $ 265 $ 3,821 $ — $ 4,469 Equity earnings in unconsolidated entities $ 47 $ — $ — $ 47 Segment adjusted EBITDA $ 281 $ 167 $ 184 $ 632 Maintenance capital $ 35 $ 9 $ 3 $ 47 (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 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K 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 Condensed 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 Condensed 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 at the time the agreement is executed or renegotiated. |
Reconciliation of segment adjusted EBITDA to net income attributable to PAA | The following table reconciles segment adjusted EBITDA to net income attributable to PAA (in millions): Three Months Ended 2017 2016 Segment adjusted EBITDA $ 512 $ 632 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (14 ) (12 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 289 (122 ) Long-term inventory costing adjustments (4) (7 ) (23 ) Deficiencies under minimum volume commitments, net (5) (11 ) (27 ) Equity-indexed compensation expense (6) (3 ) (4 ) Net gain/(loss) on foreign currency revaluation (7) 4 (1 ) Significant acquisition-related expenses (8) (5 ) — Depreciation and amortization (121 ) (114 ) Interest expense, net (129 ) (112 ) Other income/(expense), net (5 ) 5 Income before tax 510 222 Income tax expense (66 ) (19 ) Net income 444 203 Net income attributable to noncontrolling interests — (1 ) Net income attributable to PAA $ 444 $ 202 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization 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. (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 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 three months ended March 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 period were not significant to segment adjusted EBITDA. |
Organization and Basis of Con32
Organization and Basis of Consolidation and Presentation - Segments and Ownership (Details) shares in Millions | 3 Months Ended |
Mar. 31, 2017segmentshares | |
Organization | |
Operating segments number | segment | 3 |
AAP | |
Organization | |
Limited partner interest | 37.00% |
Ownership interest (in units) | shares | 288.3 |
AAP | PAGP | |
Organization | |
Limited partner interest | 53.00% |
Organization and Basis of Con33
Organization and Basis of Consolidation and Presentation - Simplification Transactions (Details) | Nov. 15, 2016 |
Simplification Transactions | PAA GP | |
Related Party Transaction [Line Items] | |
Economic general partner interest converted into non-economic interest | 2.00% |
Net Income Per Common Unit (Det
Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Nov. 15, 2016 | Mar. 31, 2017 | Mar. 31, 2016 | Nov. 14, 2016 |
Net Income Per Common Unit | ||||
General partner ownership interest | 2.00% | |||
Basic Net Income per Common Unit | ||||
Net income attributable to PAA | $ 444 | $ 202 | ||
Distributions to Series A preferred units | (34) | (23) | ||
Distributions to general partner | (155) | |||
Distributions to participating securities | (1) | (1) | ||
Undistributed loss allocated to general partner | 5 | |||
Other | (3) | |||
Net income allocated to common unitholders | 406 | 28 | ||
Diluted Net Income per Common Unit | ||||
Net income attributable to PAA | 444 | 202 | ||
Distributions to Series A preferred units | (23) | |||
Distributions to general partner | (155) | |||
Distributions to participating securities | (1) | (1) | ||
Undistributed loss allocated to general partner | 5 | |||
Net income allocated to common unitholders | $ 443 | $ 28 | ||
Common Units | ||||
Basic Net Income per Common Unit | ||||
Basic weighted average common units outstanding (units) | 691 | 398 | ||
Basic net income per common unit (usd per unit) | $ 0.59 | $ 0.07 | ||
Diluted Net Income per Common Unit | ||||
Basic weighted average common units outstanding (units) | 691 | 398 | ||
Effect of dilutive securities: | ||||
Series A preferred units (units) | 65 | |||
LTIP units (units) | 2 | 1 | ||
Diluted weighted average common units outstanding (units) | 758 | 399 | ||
Diluted net income per common unit (usd per unit) | $ 0.58 | $ 0.07 | ||
Simplification Transactions | PAA GP | ||||
Effect of dilutive securities: | ||||
Economic general partner interest converted into non-economic interest | 2.00% |
Accounts Receivable, Net (Detai
Accounts Receivable, Net (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Accounts Receivable, Net | ||
Advance cash payments received from third parties to mitigate credit risk | $ 81 | $ 89 |
Standby letters of credit | $ 46 | $ 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 |
Inventory, Linefill and Base 36
Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions | Mar. 31, 2017USD ($)$ / bbl$ / McfMcfbbl | Dec. 31, 2016USD ($)$ / bbl$ / McfMcfbbl |
Inventory by category | ||
Inventory | $ 1,219 | $ 1,343 |
Linefill and base gas | 883 | 896 |
Long-term inventory | 131 | 193 |
Total | 2,233 | 2,432 |
Crude oil | ||
Inventory by category | ||
Inventory | 1,071 | 1,049 |
Linefill and base gas | 729 | 710 |
Long-term inventory | $ 101 | $ 163 |
Inventory, Volumes (in barrels or in Mcf) | bbl | 21,710 | 23,589 |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 12,679 | 12,273 |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 2,345 | 3,279 |
Inventory, Price/Unit of measure | $ / bbl | 49.33 | 44.47 |
Linefill and base gas, Price/Unit of measure | $ / bbl | 57.50 | 57.85 |
Long-term inventory, Price/Unit of measure | $ / bbl | 43.07 | 49.71 |
NGL | ||
Inventory by category | ||
Inventory | $ 120 | $ 242 |
Linefill and base gas | 46 | 45 |
Long-term inventory | $ 30 | $ 30 |
Inventory, Volumes (in barrels or in Mcf) | bbl | 5,396 | 13,497 |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 1,646 | 1,660 |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 1,418 | 1,418 |
Inventory, Price/Unit of measure | $ / bbl | 22.24 | 17.93 |
Linefill and base gas, Price/Unit of measure | $ / bbl | 27.95 | 27.11 |
Long-term inventory, Price/Unit of measure | $ / bbl | 21.16 | 21.16 |
Natural gas | ||
Inventory by category | ||
Inventory | $ 10 | $ 32 |
Linefill and base gas | $ 108 | $ 141 |
Inventory, Volumes (in barrels or in Mcf) | Mcf | 3,630 | 14,540 |
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf | 24,976 | 30,812 |
Inventory, Price/Unit of measure | $ / Mcf | 2.75 | 2.20 |
Linefill and base gas, Price/Unit of measure | $ / Mcf | 4.32 | 4.58 |
Other | ||
Inventory by category | ||
Inventory | $ 18 | $ 20 |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Acquisitions (Details) $ in Millions | Feb. 14, 2017USD ($)abbl / dmarket_interconnectmi | Feb. 28, 2017USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2016USD ($) |
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 1,254 | $ 85 | ||
Acquisition related costs | 5 | |||
ACC Acquisition | ||||
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 1,217 | |||
Length of gathering and transmission lines (in miles) | mi | 515 | |||
Number of market interconnects | market_interconnect | 5 | |||
Additional volume enhancements to gathering system (in bbl per day) | bbl / d | 350,000 | |||
Area of acreage dedications (in acres) | a | 315,000 | |||
Acquisition related costs | $ 5 | |||
Propane marine terminal | ||||
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 41 |
Acquisitions and Dispositions38
Acquisitions and Dispositions - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions | Feb. 14, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Business Acquisition [Line Items] | |||
Goodwill | $ 2,596 | $ 2,344 | |
ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment | $ 299 | ||
Intangible assets | 641 | ||
Goodwill | 278 | ||
Other (including $4 million of cash acquired) | (1) | ||
Total | $ 1,217 | ||
Finite lived intangible assets, useful life | 20 years | ||
Cash acquired | $ 4 | ||
Minimum | ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment, useful life | 3 years | ||
Maximum | ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment, useful life | 70 years |
Acquisitions and Dispositions39
Acquisitions and Dispositions - Amortization Expense (Details) - ACC Acquisition $ in Millions | Feb. 14, 2017contract | Mar. 31, 2017USD ($) |
Business Acquisition [Line Items] | ||
Finite lived intangible assets, useful life | 20 years | |
Acreage dedication contracts | ||
Business Acquisition [Line Items] | ||
Number of acreage dedication contracts | contract | 5 | |
Finite lived intangible assets, useful life | 20 years | |
Amortization of finite lived intangible assets | $ 1 | |
Remainder of 2017 | 9 | |
2,018 | 25 | |
2,019 | 34 | |
2,020 | 42 | |
2,021 | $ 48 |
Acquisitions and Dispositions40
Acquisitions and Dispositions - Investment Acquisition (Details) - USD ($) shares in Millions, $ in Millions | Apr. 03, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Schedule of Equity Method Investments [Line Items] | |||
Equity method investment | $ 2,469 | $ 2,343 | |
Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Cash consideration | $ 26 | ||
Ownership percentage | 50.00% | ||
Equity method investment | $ 66.5 | ||
Common Units | Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Contribution of common units (units) | 1.3 | ||
Advantage Joint Venture | Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Cash consideration | $ 133 |
Acquisitions and Dispositions41
Acquisitions and Dispositions - Dispositions and Divestitures (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Dispositions | ||
Proceeds from sales of assets | $ 161 | $ 246 |
Disposed of by sale | ||
Dispositions | ||
Proceeds from sales of assets | 161 | |
Held for sale | Depreciation and amortization | ||
Dispositions | ||
Impairment related to assets held for sale | 31 | |
Held for sale | Other current assets | ||
Dispositions | ||
Assets classified as held for sale | $ 490 | |
Red River Pipeline | ||
Dispositions | ||
Interest percentage disposed of | 40.00% | |
Red River Pipeline Hewitt Segment | ||
Dispositions | ||
Interest percentage retained after disposal | 60.00% | |
Red River Pipeline from Ardmore to Longview | ||
Dispositions | ||
Interest percentage retained after disposal | 100.00% | |
Non-Core Pipeline Segment | Disposed of by sale | Depreciation and amortization | ||
Dispositions | ||
Recognized gains/(losses) related to sales of assets, net | $ 36 |
Goodwill (Details)
Goodwill (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Changes in goodwill | |
Beginning balance | $ 2,344 |
Acquisitions | 278 |
Foreign currency translation adjustments | 3 |
Dispositions and reclassifications to assets held for sale | (29) |
Ending balance | 2,596 |
Operating Segments | Transportation | |
Changes in goodwill | |
Beginning balance | 806 |
Acquisitions | 278 |
Foreign currency translation adjustments | 2 |
Ending balance | 1,086 |
Operating Segments | Facilities | |
Changes in goodwill | |
Beginning balance | 1,034 |
Foreign currency translation adjustments | 1 |
Dispositions and reclassifications to assets held for sale | (29) |
Ending balance | 1,006 |
Operating Segments | Supply and Logistics | |
Changes in goodwill | |
Beginning balance | 504 |
Ending balance | $ 504 |
Debt - Components (Details)
Debt - Components (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Jan. 31, 2017 | Dec. 31, 2016 |
Short-term debt: | |||
Total short-term debt | $ 1,341 | $ 1,715 | |
Long-term debt: | |||
Senior notes, net of unamortized discounts and debt issuance costs of $74 and $76, respectively | 9,876 | 9,874 | |
Other long-term debt | 3 | 250 | |
Total long-term debt | 9,879 | 10,124 | |
Total debt | 11,220 | $ 11,839 | |
Commercial paper notes | |||
Long-term debt: | |||
Weighted average interest rate, long-term | 1.60% | ||
Other long-term debt | $ 247 | ||
Senior notes | |||
Long-term debt: | |||
Unamortized discounts and debt issuance costs | 74 | 76 | |
Senior notes, net of unamortized discounts and debt issuance costs of $74 and $76, respectively | 9,876 | 9,874 | |
Other | |||
Long-term debt: | |||
Other long-term debt | $ 3 | $ 3 | |
Commercial paper notes | |||
Short-term debt: | |||
Weighted average interest rate, short-term | 1.90% | 1.60% | |
Short-term debt | $ 958 | $ 563 | |
Other | |||
Short-term debt: | |||
Other short-term debt | $ 133 | $ 2 | |
Senior secured hedged inventory facility | Credit facility | |||
Short-term debt: | |||
Weighted average interest rate, short-term | 2.00% | 1.80% | |
Short-term debt | $ 250 | $ 750 | |
6.13% senior notes due January 2017 | Senior notes | |||
Short-term debt: | |||
Debt instrument, interest rate | 6.13% | 6.13% | |
Senior notes, current | $ 400 |
Debt - Fair Value, Activity, L
Debt - Fair Value, Activity, Letters of Credit, Borrowings and Repayments (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | ||
Jan. 31, 2017 | Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Debt | ||||
Short-term debt | $ 1,341 | $ 1,715 | ||
Repayments of senior notes | 400 | |||
Letters of credit | ||||
Debt | ||||
Outstanding letters of credit | 77 | 73 | ||
Senior notes | ||||
Debt | ||||
Debt instrument face value | 9,900 | $ 10,300 | ||
Senior notes | 6.13% senior notes due January 2016 | ||||
Debt | ||||
Repayments of senior notes | $ 400 | |||
Debt instrument, interest rate | 6.13% | 6.13% | ||
Senior notes | Level 2 | ||||
Debt | ||||
Debt instrument fair value | 10,100 | $ 10,400 | ||
Credit facilities and commercial paper program | ||||
Debt | ||||
Total borrowings | 18,800 | $ 10,800 | ||
Total repayments | 19,200 | $ 12,300 | ||
Exchange Traded | ||||
Debt | ||||
Short-term debt | $ 95 | $ 410 |
Partners' Capital and Distrib45
Partners' Capital and Distributions - Units Outstanding (Details) - shares | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Series A Preferred Units | ||
Activity for preferred units and common units | ||
Outstanding, beginning of period (units) | 64,388,853 | |
Outstanding, end of period (units) | 65,676,626 | |
Series A Preferred Units | Limited Partners | Partners’ Capital Excluding Noncontrolling Interests | ||
Activity for preferred units and common units | ||
Outstanding, beginning of period (units) | 64,388,853 | 0 |
Issuance of preferred units in connection with in-kind distributions (units) | 1,287,773 | |
Sale of preferred units (units) | 61,030,127 | |
Outstanding, end of period (units) | 65,676,626 | 61,030,127 |
Common Units | ||
Activity for preferred units and common units | ||
Outstanding, beginning of period (units) | 669,194,419 | |
Sales of common units (units) | 54,119,893 | |
Outstanding, end of period (units) | 723,404,994 | |
Common Units | Limited Partners | Partners’ Capital Excluding Noncontrolling Interests | ||
Activity for preferred units and common units | ||
Outstanding, beginning of period (units) | 669,194,419 | 397,727,624 |
Sales of common units (units) | 54,119,893 | |
Issuance of common units under LTIP (units) | 90,682 | 3,367 |
Outstanding, end of period (units) | 723,404,994 | 397,730,991 |
Partners' Capital and Distrib46
Partners' Capital and Distributions - Sale of Units (Details) - Common Units - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended |
Mar. 31, 2017 | Mar. 31, 2017 | |
Subsidiary, Sale of Stock [Line Items] | ||
Sale of common units (units) | 54,119,893 | |
Sale of common units, net proceeds | $ 1,664 | |
Continuous Offering Program | ||
Subsidiary, Sale of Stock [Line Items] | ||
Sale of common units (units) | 4,033,567 | |
Sale of common units, net proceeds | $ 129 | |
Commissions paid to sales agents | $ 1 | |
Omnibus Agreement | ||
Subsidiary, Sale of Stock [Line Items] | ||
Sale of common units (units) | 50,086,326 | |
Sale of common units, net proceeds | $ 1,535 | |
Omnibus Agreement | AAP | Continuous Offering Program | ||
Subsidiary, Sale of Stock [Line Items] | ||
Sale of common units (units) | 1,800,000 | |
Omnibus Agreement | AAP | Underwritten Offering | ||
Subsidiary, Sale of Stock [Line Items] | ||
Sale of common units (units) | 48,300,000 |
Partners' Capital and Distrib47
Partners' Capital and Distributions - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | May 15, 2017 | Feb. 14, 2017 | Mar. 31, 2017 | Mar. 31, 2016 |
Partners Capital and Distributions | ||||
Total distributions paid | $ 372 | $ 434 | ||
Partners’ Capital Excluding Noncontrolling Interests | ||||
Partners Capital and Distributions | ||||
Total distributions paid | $ 371 | $ 433 | ||
Common Units | Cash Distributions | ||||
Partners Capital and Distributions | ||||
Total distributions paid | $ 371 | |||
Distributions per common unit, paid (usd per unit) | $ 0.55 | |||
Common Units | Cash Distributions | Forecast | ||||
Partners Capital and Distributions | ||||
Total distributions paid | $ 399 | |||
Distributions per common unit, paid (usd per unit) | $ 0.55 | |||
Series A Preferred Units | Partners’ Capital Excluding Noncontrolling Interests | In-Kind Distributions | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 34 | |||
Distribution of units in lieu of cash (units) | 1,287,773 | |||
Series A Preferred Units | Partners’ Capital Excluding Noncontrolling Interests | In-Kind Distributions | Forecast | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 34 | |||
Distribution of units in lieu of cash (units) | 1,313,527 | |||
Public | Common Units | Cash Distributions | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 237 | |||
Public | Common Units | Cash Distributions | Forecast | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 240 | |||
AAP | Common Units | Cash Distributions | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 134 | |||
AAP | Common Units | Cash Distributions | Forecast | ||||
Partners Capital and Distributions | ||||
Distributions to unitholders | $ 159 |
Derivatives and Risk Manageme48
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions | 3 Months Ended |
Mar. 31, 2017MWhMcfbbl | |
Net long position associated with crude oil purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 2.6 |
Net short time spread position hedging anticipated crude oil lease gathering purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 4.6 |
Crude oil grade basis position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 42.1 |
Net short position related to anticipated sales of natural gas inventory | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | Mcf | 3.5 |
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) | 24 |
PLA oil long call option position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 0.8 |
Long natural gas position for natural gas purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | Mcf | 56.7 |
Short propane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 10.1 |
Short butane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 3.1 |
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 Manageme49
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($)contract | |
8 forward starting interest rate swaps (30-year), 3.14% | |
Interest Rate Risk Hedging | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 3.14% |
8 forward starting interest rate swaps (30-year), 3.20% | |
Interest Rate Risk Hedging | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 3.20% |
8 forward starting interest rate swaps (30-year), 2.83% | |
Interest Rate Risk Hedging | |
Number of interest rate derivatives | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 2.83% |
Derivatives and Risk Manageme50
Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) CAD in Millions, $ in Millions | Mar. 31, 2017CADCAD / $ | Mar. 31, 2017USD ($)CAD / $ |
Forward exchange contracts that exchange CAD for USD maturing in 2017 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | CAD 234 | $ 175 |
Average exchange rate (cad per usd) | 1.34 | 1.34 |
Forward exchange contracts that exchange USD for CAD maturing in 2017 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | CAD 569 | $ 428 |
Average exchange rate (cad per usd) | 1.33 | 1.33 |
Derivatives and Risk Manageme51
Derivatives and Risk Management Activities - Embedded Derivatives (Details) - Preferred Distribution Rate Reset Option - Series A Preferred Units $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Embedded Derivatives | |
Fair value of derivative liability | $ 36 |
Loss recognized due to changes in fair value | $ 4 |
Derivatives and Risk Manageme52
Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | $ 89 | $ 36 |
Commodity Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | 96 | 32 |
Commodity Derivatives | Transportation segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | 2 | |
Commodity Derivatives | Field operating costs | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | (3) | (2) |
Interest Rate Derivatives | Interest expense, net | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | (2) | (2) |
Foreign Currency Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | 2 | 6 |
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 | (4) | |
Derivatives in Hedging Relationships | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | (2) | (1) |
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 | 1 | |
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 | (2) | (2) |
Derivatives Not Designated as a Hedge | ||
Impact of derivative activities recognized in earnings | ||
Total gain/(loss) on derivatives recognized in net income | 91 | 37 |
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 | 96 | 31 |
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 | 2 | |
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 | (3) | (2) |
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 | 2 | $ 6 |
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 | $ (4) |
Derivatives and Risk Manageme53
Derivatives and Risk Management Activities - Assets and Liabilities (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017USD ($)contract | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($)contract | |
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | $ 96 | $ 108 | |
Liability Derivatives Fair Value | (183) | (481) | |
Broker receivable | 95 | $ 410 | |
Net loss deferred in AOCI | 219 | ||
Net loss expected to be reclassified to earnings in the next twelve months | 8 | ||
Remaining loss expected to be reclassified to earnings through 2049 | $ 211 | ||
Number of outstanding derivatives containing credit-risk related contingent features | contract | 0 | 0 | |
Interest Rate Derivatives | |||
Derivative assets and liabilities | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | $ 7 | $ (90) | |
Derivatives in Hedging Relationships | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | (43) | $ (50) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | (20) | (23) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | (23) | (27) | |
Derivatives Not Designated as a Hedge | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 96 | 108 | |
Liability Derivatives Fair Value | (140) | (431) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 79 | 101 | |
Liability Derivatives Fair Value | (81) | (344) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 13 | 2 | |
Liability Derivatives Fair Value | (8) | (1) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 2 | ||
Liability Derivatives Fair Value | (7) | (14) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 2 | ||
Liability Derivatives Fair Value | (4) | (34) | |
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 1 | ||
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 1 | 3 | |
Liability Derivatives Fair Value | (4) | (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 | $ (36) | $ (32) |
Derivatives and Risk Manageme54
Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Initial margin | $ 92 | $ 119 |
Variation margin posted/(returned) | 3 | 291 |
Net broker receivable/(payable) | $ 95 | $ 410 |
Derivatives and Risk Manageme55
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative Asset Positions | ||
Gross Position - Asset | $ 96 | $ 108 |
Netting adjustment | (92) | (350) |
Cash collateral paid | 95 | 410 |
Net Position - Asset | 99 | 168 |
Derivative Liability Positions | ||
Gross Position - Liability | (183) | (481) |
Netting adjustment | 92 | 350 |
Net Position - Liability | (91) | (131) |
Other current assets | ||
Derivative Asset Positions | ||
Net Position - Asset | 94 | 167 |
Other long-term assets, net | ||
Derivative Asset Positions | ||
Net Position - Asset | 5 | 1 |
Other current liabilities | ||
Derivative Liability Positions | ||
Net Position - Liability | (28) | (40) |
Other long-term liabilities and deferred credits | ||
Derivative Liability Positions | ||
Net Position - Liability | $ (63) | $ (91) |
Derivatives and Risk Manageme56
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Level 3 | |||
Rollforward of Level 3 Net Asset/(Liability) | |||
Beginning Balance | $ (36) | $ 11 | |
Net losses for the period included in earnings | (3) | (1) | |
Settlements | 3 | (9) | |
Derivatives entered into during the period | (60) | ||
Ending Balance | (36) | (59) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | (2) | $ (1) | |
Recurring Fair Value Measures | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (87) | $ (373) | |
Recurring Fair Value Measures | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (6) | (288) | |
Recurring Fair Value Measures | Interest Rate Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (43) | (50) | |
Recurring Fair Value Measures | Foreign Currency Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (2) | (3) | |
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (36) | (32) | |
Recurring Fair Value Measures | Level 1 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (6) | (113) | |
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (6) | (113) | |
Recurring Fair Value Measures | Level 2 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (45) | (224) | |
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (171) | ||
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (43) | (50) | |
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (2) | (3) | |
Recurring Fair Value Measures | Level 3 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (36) | (36) | |
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (4) | ||
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | $ (36) | $ (32) |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) - Common Units - shares | 1 Months Ended | 3 Months Ended |
Mar. 31, 2017 | Mar. 31, 2017 | |
Related Party Transaction [Line Items] | ||
Sale of common units (units) | 54,119,893 | |
Continuous Offering Program | ||
Related Party Transaction [Line Items] | ||
Sale of common units (units) | 4,033,567 | |
Continuous Offering Program | AAP | ||
Related Party Transaction [Line Items] | ||
Sale of common units (units) | 1,800,000 | |
Underwritten Offering | AAP | ||
Related Party Transaction [Line Items] | ||
Sale of common units (units) | 48,300,000 |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Oxy | |||
Related Party Transaction [Line Items] | |||
Revenues | $ 234 | $ 112 | |
Purchases and related costs | (40) | $ (46) | |
Trade accounts receivable and other receivables | 872 | $ 789 | |
Accounts payable | $ 818 | $ 836 | |
AAP | |||
Related Party Transaction [Line Items] | |||
Limited partner interest | 37.00% | ||
AAP | Oxy | |||
Related Party Transaction [Line Items] | |||
Limited partner interest | 10.00% |
Commitments and Contingencies (
Commitments and Contingencies (Details) | May 16, 2016countemployee | Jan. 06, 2016occasion | Jan. 01, 2015bbl | May 31, 2015bbl | Mar. 31, 2017USD ($)lawsuit | Dec. 31, 2016USD ($) | Apr. 30, 2015violation |
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities | $ 139,000,000 | $ 147,000,000 | |||||
Estimated undiscounted reserve for environmental liabilities, short-term | 59,000,000 | 61,000,000 | |||||
Estimated undiscounted reserve for environmental liabilities, long-term | 80,000,000 | 86,000,000 | |||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 47,000,000 | 56,000,000 | |||||
Trade accounts receivable and other receivables, net | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 34,000,000 | 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 | 13,000,000 | $ 17,000,000 | |||||
Line 901 Incident | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities | 68,000,000 | ||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 41,000,000 | ||||||
Estimated size of release (in bbl) | bbl | 2,934 | ||||||
Estimated size of release to reach Pacific Ocean (in bbl) | bbl | 598 | ||||||
Fines or penalties assessed | 0 | ||||||
Aggregate total estimated costs | 280,000,000 | ||||||
Recoveries from insurance carriers | 156,000,000 | ||||||
Total release costs probable of recovery | 197,000,000 | ||||||
Line 901 Incident | Trade accounts receivable and other receivables, net | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 29,000,000 | ||||||
Line 901 Incident | Accounts payable and accrued liabilities | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Estimated undiscounted reserve for environmental liabilities, short-term | $ 48,000,000 | ||||||
Line 901 Incident | May 2016 Indictment | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Number of employees charged | employee | 1 | ||||||
Total counts included in the indictment | count | 46 | ||||||
Number of misdemeanor charges relating to wildlife allegedly taken | count | 36 | ||||||
Number of counts relating to the release of crude oil or reporting of the release | count | 10 | ||||||
Number of felony charges | count | 3 | ||||||
Number of misdemeanor charges relating to the release of crude oil or reporting of the release | count | 7 | ||||||
Line 901 Incident | Class Action Lawsuits | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Number of cases filed during the period | lawsuit | 9 | ||||||
Number of cases 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 | ||||||
Number of cases consolidated into a single proceeding | lawsuit | 2 | ||||||
Number of remaining lawsuits | lawsuit | 2 | ||||||
Line 901 Incident | Production of Books And Records Lawsuits | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Number of cases filed during the period | lawsuit | 2 | ||||||
In the Matter of Bakersfield Crude Terminal LLC et al | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Fines or penalties assessed | $ 0 | ||||||
Number of alleged rule violations | violation | 10 | ||||||
Mesa to Basin Pipeline | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Estimated size of release (in bbl) | bbl | 500 | ||||||
Mesa to Basin Pipeline | PHMSA | |||||||
Legal, Environmental or Regulatory Matters | |||||||
Fines or penalties assessed | $ 184,300 | ||||||
Number of occasions of alleged failure to carry out damage prevention program and other procedures | occasion | 4 |
Operating Segments - Segment F
Operating Segments - Segment Financial Data (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2017USD ($)segment | Mar. 31, 2016USD ($) | |
Segment Reporting Information [Line Items] | ||
Operating segments number | segment | 3 | |
Revenues: | ||
Revenues | $ 6,667 | $ 4,111 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Equity earnings in unconsolidated entities | 53 | 47 |
Segment adjusted EBITDA | 512 | 632 |
Maintenance capital | 59 | 47 |
Transportation | ||
Revenues: | ||
Revenues | 225 | 241 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Equity earnings in unconsolidated entities | 53 | 47 |
Segment adjusted EBITDA | 273 | 281 |
Maintenance capital | 29 | 35 |
Facilities | ||
Revenues: | ||
Revenues | 134 | 138 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Segment adjusted EBITDA | 188 | 167 |
Maintenance capital | 27 | 9 |
Supply and Logistics | ||
Revenues: | ||
Revenues | 6,395 | 3,819 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Segment adjusted EBITDA | 51 | 184 |
Maintenance capital | 3 | 3 |
Operating Segments | ||
Revenues: | ||
Revenues | 7,082 | 4,469 |
Operating Segments | Transportation | ||
Revenues: | ||
Revenues | 389 | 383 |
Operating Segments | Facilities | ||
Revenues: | ||
Revenues | 293 | 265 |
Operating Segments | Supply and Logistics | ||
Revenues: | ||
Revenues | 6,400 | 3,821 |
Intersegment | ||
Revenues: | ||
Revenues | (415) | (358) |
Intersegment | Transportation | ||
Revenues: | ||
Revenues | (164) | (142) |
Intersegment | Facilities | ||
Revenues: | ||
Revenues | (159) | (127) |
Intersegment | Supply and Logistics | ||
Revenues: | ||
Revenues | (5) | (2) |
Intersegment Adjustment | ||
Revenues: | ||
Revenues | $ (87) | $ (87) |
Operating Segments - Reconcili
Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Segment Reporting [Abstract] | ||
Segment adjusted EBITDA | $ 512 | $ 632 |
Adjustments: | ||
Depreciation and amortization of unconsolidated entities | (14) | (12) |
Gains/(losses) from derivative activities net of inventory valuation adjustments | 289 | (122) |
Long-term inventory costing adjustments | (7) | (23) |
Deficiencies under minimum volume commitments, net | (11) | (27) |
Equity-indexed compensation expense | (3) | (4) |
Net gain/(loss) on foreign currency revaluation | 4 | (1) |
Significant acquisition-related expenses | (5) | |
Depreciation and amortization | (121) | (114) |
Interest expense, net | (129) | (112) |
Other income/(expense), net | (5) | 5 |
INCOME BEFORE TAX | 510 | 222 |
Income tax expense | (66) | (19) |
NET INCOME | 444 | 203 |
Net income attributable to noncontrolling interests | 0 | (1) |
NET INCOME ATTRIBUTABLE TO PAA | $ 444 | $ 202 |