Cover Page
Cover Page - shares | 9 Months Ended | |
Sep. 30, 2019 | Oct. 31, 2019 | |
Cover page. | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2019 | |
Document Transition Report | false | |
Entity File Number | 1-36132 | |
Entity Registrant Name | PLAINS GP HOLDINGS LP | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 90-1005472 | |
Entity Address, Address Line One | 333 Clay Street | |
Entity Address, Address Line Two | Suite 1600 | |
Entity Address, City or Town | Houston | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77002 | |
City Area Code | 713 | |
Local Phone Number | 646-4100 | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Small Business Entity | false | |
Emerging Growth Company | false | |
Entity Shell Company | false | |
Title of 12(b) Security | Class A Shares | |
Trading Symbol | PAGP | |
Security Exchange Name | NYSE | |
Entity Common Stock, Shares Outstanding (shares) | 182,006,009 | |
Entity Central Index Key | 0001581990 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q3 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 611 | $ 69 |
Restricted cash | 59 | |
Trade accounts receivable and other receivables, net | 2,912 | 2,454 |
Inventory | 816 | 640 |
Other current assets | 280 | 373 |
Total current assets | 4,678 | 3,536 |
PROPERTY AND EQUIPMENT | 18,729 | 17,905 |
Accumulated depreciation | (3,460) | (3,103) |
Property and equipment, net | 15,269 | 14,802 |
OTHER ASSETS | ||
Goodwill | 2,532 | 2,521 |
Investments in unconsolidated entities | 3,485 | 2,702 |
Deferred tax asset | 1,301 | 1,304 |
Linefill and base gas | 930 | 916 |
Long-term operating lease right-of-use assets, net | 443 | |
Long-term inventory | 159 | 136 |
Other long-term assets, net | 893 | 913 |
Total assets | 29,690 | 26,830 |
CURRENT LIABILITIES | ||
Trade accounts payable | 3,034 | 2,705 |
Short-term debt | 1,084 | 66 |
Other current liabilities | 755 | 687 |
Total current liabilities | 4,873 | 3,458 |
LONG-TERM LIABILITIES | ||
Senior notes, net | 8,937 | 8,941 |
Other long-term debt, net | 236 | 202 |
Long-term operating lease liabilities | 348 | |
Other long-term liabilities and deferred credits | 873 | 910 |
Total long-term liabilities | 10,394 | 10,053 |
COMMITMENTS AND CONTINGENCIES (NOTE 13) | ||
PARTNERS’ CAPITAL | ||
Noncontrolling interests | 12,268 | 11,473 |
Total partners’ capital | 14,423 | 13,319 |
Total liabilities and partners’ capital | 29,690 | 26,830 |
Class A Shares | ||
PARTNERS’ CAPITAL | ||
Class A shareholders (182,006,009 and 159,485,588 shares outstanding, respectively) | $ 2,155 | $ 1,846 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 |
Class A Shares | ||||||||
Shares outstanding | ||||||||
Shares outstanding (shares) | 182,006,009 | 166,817,333 | 159,485,588 | 159,485,588 | 159,160,785 | 157,954,130 | 157,019,038 | 156,111,139 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
REVENUES | ||||
Total revenues | $ 7,886 | $ 8,792 | $ 24,515 | $ 25,269 |
COSTS AND EXPENSES | ||||
Purchases and related costs | 6,855 | 7,768 | 21,218 | 22,838 |
Field operating costs | 316 | 326 | 983 | 931 |
General and administrative expenses | 75 | 75 | 229 | 235 |
Depreciation and amortization | 157 | 129 | 441 | 386 |
(Gains)/losses on asset sales and asset impairments, net | (7) | 2 | (7) | (79) |
Total costs and expenses | 7,396 | 8,300 | 22,864 | 24,311 |
OPERATING INCOME | 490 | 492 | 1,651 | 958 |
OTHER INCOME/(EXPENSE) | ||||
Equity earnings in unconsolidated entities | 102 | 110 | 274 | 281 |
Gain on investment in unconsolidated entities | 4 | 210 | 271 | 210 |
Interest expense (net of capitalized interest of $7, $8, $29 and $21, respectively) | (108) | (110) | (311) | (327) |
Other income/(expense), net | 5 | (3) | 23 | 8 |
INCOME BEFORE TAX | 493 | 699 | 1,908 | 1,130 |
Current income tax expense | (19) | (14) | (72) | (34) |
Deferred income tax expense | (43) | (9) | (65) | (50) |
NET INCOME | 431 | 676 | 1,771 | 1,046 |
Net income attributable to noncontrolling interests | (361) | (565) | (1,488) | (892) |
NET INCOME ATTRIBUTABLE TO PAGP | $ 70 | $ 111 | $ 283 | $ 154 |
Class A Shares | ||||
OTHER INCOME/(EXPENSE) | ||||
BASIC NET INCOME PER CLASS A SHARE (in dollars per share) | $ 0.41 | $ 0.70 | $ 1.73 | $ 0.98 |
DILUTED NET INCOME PER CLASS A SHARE (in dollars per share) | $ 0.41 | $ 0.70 | $ 1.72 | $ 0.98 |
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (in shares) | 168 | 158 | 163 | 157 |
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (in shares) | 168 | 158 | 165 | 157 |
Supply and Logistics | ||||
REVENUES | ||||
Total revenues | $ 7,541 | $ 8,482 | $ 23,477 | $ 24,374 |
Transportation | ||||
REVENUES | ||||
Total revenues | 196 | 161 | 581 | 458 |
OTHER INCOME/(EXPENSE) | ||||
Equity earnings in unconsolidated entities | 102 | 110 | 274 | 281 |
Facilities | ||||
REVENUES | ||||
Total revenues | $ 149 | $ 149 | $ 457 | $ 437 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Income Statement [Abstract] | ||||
Interest expense, capitalized interest | $ 7 | $ 8 | $ 29 | $ 21 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 431 | $ 676 | $ 1,771 | $ 1,046 |
Other comprehensive income/(loss) | (99) | 76 | 10 | (46) |
Comprehensive income | 332 | 752 | 1,781 | 1,000 |
Comprehensive income attributable to noncontrolling interests | (285) | (624) | (1,496) | (856) |
Comprehensive income attributable to PAGP | $ 47 | $ 128 | $ 285 | $ 144 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Total period activity | $ (99) | $ 76 | $ 10 | $ (46) |
Derivative Instruments | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Balance at beginning of period | (177) | (223) | ||
Reclassification adjustments | 7 | 6 | ||
Unrealized gain/(loss) on hedges | (111) | 60 | ||
Total period activity | (104) | 66 | ||
Balance at end of period | (281) | (157) | (281) | (157) |
Translation Adjustments | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Balance at beginning of period | (853) | (548) | ||
Currency translation adjustments | 113 | (112) | ||
Total period activity | 113 | (112) | ||
Balance at end of period | (740) | (660) | (740) | (660) |
Other | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Balance at beginning of period | 1 | |||
Other | 1 | |||
Total period activity | 1 | |||
Balance at end of period | 1 | 1 | 1 | 1 |
Total | ||||
Changes in Accumulated Other Comprehensive Income/(Loss) | ||||
Balance at beginning of period | (1,030) | (770) | ||
Reclassification adjustments | 7 | 6 | ||
Unrealized gain/(loss) on hedges | (111) | 60 | ||
Currency translation adjustments | 113 | (112) | ||
Other | 1 | |||
Total period activity | 10 | (46) | ||
Balance at end of period | $ (1,020) | $ (816) | $ (1,020) | $ (816) |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income | $ 1,771 | $ 1,046 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation and amortization | 441 | 386 |
(Gains)/losses on asset sales and asset impairments, net | (7) | (79) |
Equity-indexed compensation expense | 31 | 59 |
Inventory valuation adjustments | 11 | |
Deferred income tax expense | 65 | 50 |
Settlement of terminated interest rate hedging instruments | (55) | 14 |
Change in fair value of Preferred Distribution Rate Reset Option (Note 10) | (16) | (3) |
Equity earnings in unconsolidated entities | (274) | (281) |
Distributions on earnings from unconsolidated entities | 307 | 324 |
Gain on investment in unconsolidated entities | (271) | (210) |
Other | 22 | 22 |
Changes in assets and liabilities, net of acquisitions | (251) | (36) |
Net cash provided by operating activities | 1,774 | 1,292 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Cash paid in connection with acquisitions, net of cash acquired | (47) | |
Investments in unconsolidated entities | (367) | (300) |
Additions to property, equipment and other | (919) | (1,184) |
Proceeds from sales of assets | 8 | 1,298 |
Return of investment from unconsolidated entities | 10 | |
Cash paid for purchases of linefill and base gas | (33) | |
Other investing activities | (9) | (8) |
Net cash used in investing activities | (1,367) | (184) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Net repayments under PAA commercial paper program (Note 8) | (63) | |
Net repayments under PAA senior secured hedged inventory facility (Note 8) | (479) | |
Proceeds from PAA GO Zone term loans | 200 | |
Proceeds from the issuance of PAA senior notes (Note 8) | 998 | |
Distributions paid to Class A shareholders (Note 9) | (165) | (142) |
Distributions paid to noncontrolling interests (Note 9) | (717) | (611) |
Sale of noncontrolling interest in a subsidiary (Note 9) | 128 | |
Other financing activities | (45) | (17) |
Net cash provided by/(used in) financing activities | 199 | (1,112) |
Effect of translation adjustment | (5) | (3) |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 601 | (7) |
Cash and cash equivalents and restricted cash, beginning of period | 69 | 40 |
Cash and cash equivalents and restricted cash, end of period | 670 | 33 |
Cash paid for: | ||
Interest, net of amounts capitalized | 263 | 281 |
Income taxes, net of amounts refunded | $ 110 | $ 20 |
CONDENSED CONSOLIDATED STATEM_6
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Total | Noncontrolling Interests | Limited PartnersClass A Shares |
Increase (Decrease) in Partners' Capital | |||
Impact of adoption of ASU 2017-05 | ASU 2017-05 | $ 113 | $ 89 | $ 24 |
Beginning balance, adjusted balance | 12,471 | 10,752 | 1,719 |
Beginning balance at Dec. 31, 2017 | 12,358 | 10,663 | 1,695 |
Increase (Decrease) in Partners' Capital | |||
Net income | 1,046 | 892 | 154 |
Distributions (Note 9) | (802) | (660) | (142) |
Deferred tax asset | 11 | 11 | |
Other comprehensive income/(loss) | (46) | (36) | (10) |
Change in ownership interest in connection with Exchange Right exercises (Note 9) | (6) | 6 | |
Equity-indexed compensation expense | 37 | 31 | 6 |
Other | (6) | (9) | 3 |
Ending balance at Sep. 30, 2018 | 12,711 | 10,964 | 1,747 |
Beginning balance at Jun. 30, 2018 | 12,215 | 10,554 | 1,661 |
Increase (Decrease) in Partners' Capital | |||
Net income | 676 | 565 | 111 |
Distributions (Note 9) | (267) | (219) | (48) |
Deferred tax asset | 2 | 2 | |
Other comprehensive income/(loss) | 76 | 59 | 17 |
Change in ownership interest in connection with Exchange Right exercises (Note 9) | (3) | 3 | |
Equity-indexed compensation expense | 14 | 12 | 2 |
Other | (5) | (4) | (1) |
Ending balance at Sep. 30, 2018 | 12,711 | 10,964 | 1,747 |
Beginning balance at Dec. 31, 2018 | 13,319 | 11,473 | 1,846 |
Increase (Decrease) in Partners' Capital | |||
Net income | 1,771 | 1,488 | 283 |
Distributions (Note 9) | (894) | (729) | (165) |
Deferred tax asset | 92 | 92 | |
Other comprehensive income/(loss) | 10 | 8 | 2 |
Change in ownership interest in connection with Exchange Right exercises (Note 9) | (100) | 100 | |
Equity-indexed compensation expense | 14 | 10 | 4 |
Sale of noncontrolling interest in a subsidiary (Note 9) | 128 | 128 | |
Other | (17) | (10) | (7) |
Ending balance at Sep. 30, 2019 | 14,423 | 12,268 | 2,155 |
Beginning balance at Jun. 30, 2019 | 14,342 | 12,306 | 2,036 |
Increase (Decrease) in Partners' Capital | |||
Net income | 431 | 361 | 70 |
Distributions (Note 9) | (315) | (255) | (60) |
Deferred tax asset | 65 | 65 | |
Other comprehensive income/(loss) | (99) | (76) | (23) |
Change in ownership interest in connection with Exchange Right exercises (Note 9) | (69) | 69 | |
Equity-indexed compensation expense | 6 | 5 | 1 |
Other | (7) | (4) | (3) |
Ending balance at Sep. 30, 2019 | $ 14,423 | $ 12,268 | $ 2,155 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 9 Months Ended |
Sep. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Consolidation and Presentation | Organization and Basis of Consolidation and Presentation Organization Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in July 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of September 30, 2019 , its principal sources of cash flow are derived from an indirect investment in Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. As used in this Form 10-Q and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries. As of September 30, 2019 , PAGP owned (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 73% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately 181.0 million Class A units of AAP (“AAP units”) and indirect ownership of approximately 1.0 million AAP units through GP LLC. GP LLC is a Delaware limited liability company that also holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of September 30, 2019 , directly owned a limited partner interest in PAA through its ownership of approximately 252.2 million PAA common units (approximately 32% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA. PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil, natural gas liquids (“NGL”) and natural gas. PAA owns 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 14 for further discussion of our operating segments. PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC. 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 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 ISDA = International Swaps and Derivatives Association LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet MMbls = Million barrels NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange SEC = United States Securities and Exchange Commission TWh = Terawatt hour 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 2018 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP 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. Effective for the fourth quarter of 2018, we present “(Gains)/losses on asset sales and asset impairments, net” as a separate line item on our Condensed Consolidated Statements of Operations. To conform to the current year presentation, amounts related to gains and losses on asset sales and asset impairments previously presented in “Depreciation and amortization” are now presented in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statements of Operations. This change was applied retrospectively and does not affect Operating income, Net income or Net income attributable to PAGP. The condensed consolidated balance sheet data as of December 31, 2018 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2019 should not be taken as indicative of results to be expected for the entire year. Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary. We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because: • The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively. • AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA. • PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP. With the exception of a deferred tax asset of $1.301 billion and $1.304 billion as of September 30, 2019 and December 31, 2018 , respectively, substantially all assets and liabilities presented on PAGP’s Condensed Consolidated Balance Sheet are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the nine months ended September 30, 2019 or the year ended December 31, 2018 . See Note 16 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into in connection with the Simplification Transactions. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2019 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Restricted Cash Restricted cash includes cash held by us that is unavailable for general use and is comprised of amounts advanced to us by certain equity method investees related to the construction of fixed assets where we serve as construction manager. The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Condensed Consolidated Balance Sheet that sum to the total of the amounts shown on our Condensed Consolidated Statement of Cash Flows as of the end of the period (in millions): September 30, Cash and cash equivalents $ 611 Restricted cash 59 Total cash and cash equivalents and restricted cash $ 670 We did not have any restricted cash as of December 31, 2018. Recent Accounting Pronouncements Except as discussed below and in our 2018 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2019 that are of significance or potential significance to us. Accounting Standards Updates Adopted During the Period In February 2016, the FASB issued ASU 2016-02, Leases , (followed by a series of related accounting standard updates (collectively referred to as “Topic 842”)), that revises the historical accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of right-of-use assets and lease liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance became effective for interim and annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019. Our adoption resulted in the recording of additional net lease right-of-use assets and lease liabilities of approximately $560 million and $570 million , respectively, on January 1, 2019 and did not have a material impact on our results of operations or cash flows. We elected the package of practical expedients permitted under the transition guidance within Topic 842, which, among other things, allowed us to carry forward the historical accounting related to lease identification, classification and indirect costs. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements (including rights of way) on existing agreements. Additionally, we elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee and for all classes of assets where we are the lessor. Further, we elected the practical expedient which provides us with an optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods and, if necessary, recognizing a cumulative-effect adjustment to the opening balance of Partners’ Capital upon adoption. There was no impact to retained earnings related to our adoption. We did not elect the practical expedient related to using hindsight in determining the lease term as this was not relevant following our election of the optional transitional method. We implemented a process to evaluate the impact of adopting this guidance on each type of lease contract we have entered into with counterparties. Our implementation team determined appropriate changes to our business processes, systems and controls to support recognition and disclosure under Topic 842. In addition to the above, which primarily relates to our accounting as a lessee, our accounting from a lessor perspective remains substantially unchanged under Topic 842. See Note 11 for information about our leases. We also adopted the ASUs listed below effective January 1, 2019 and our adoption did not have a material impact to our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for additional information regarding these ASUs): • ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes; • ASU 2018-09, Codification Improvements; • ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting; and • ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Accounting Standards Updates Issued During the Period In July 2019, the FASB issued 2019-07, Codification Updates to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates , which amended SEC paragraphs in the ASC to reflect the SEC final rule releases Disclosure Update and Simplification, Investment Company Reporting Modernization and other miscellaneous updates. This guidance is effective upon issuance and did not have a material impact on our financial position, results of operations or cash flows. In May 2019, the FASB issued 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief , which provides transition relief and allows entities to elect the fair value option on certain financial instruments. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption will have on our financial position, results of operations and cash flows. In April 2019, the FASB issued 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments , which clarifies certain aspects of accounting for credit losses, hedging activities and financial instruments. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption will have on our financial position, results of operations and cash flows. |
Revenues and Accounts Receivabl
Revenues and Accounts Receivable | 9 Months Ended |
Sep. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenues and Accounts Receivable | Revenues and Accounts Receivable Revenue Recognition We disaggregate our revenues by segment and type of activity under ASC Topic 606, Revenues from Contracts with Customers (“Topic 606”). These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition. The following tables present our Supply and Logistics segment, Transportation segment and Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 7,185 $ 7,978 $ 21,716 $ 22,651 NGL and other transactions 202 556 1,380 2,181 Total Supply and Logistics segment revenues from contracts with customers $ 7,387 $ 8,534 $ 23,096 $ 24,832 Three Months Ended Nine Months Ended 2019 2018 2019 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 532 $ 435 $ 1,504 $ 1,237 NGL pipelines 25 25 75 76 Total tariff activities 557 460 1,579 1,313 Trucking 33 36 106 103 Total Transportation segment revenues from contracts with customers $ 590 $ 496 $ 1,685 $ 1,416 Three Months Ended Nine Months Ended 2019 2018 2019 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 174 $ 174 $ 523 $ 511 NGL and natural gas processing and fractionation 87 87 262 278 Rail load / unload 20 24 58 56 Total Facilities segment revenues from contracts with customers $ 281 $ 285 $ 843 $ 845 Reconciliation to Total Revenues of Reportable Segments. The following tables present the reconciliation of our revenues from contracts with customers to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions): Three Months Ended September 30, 2019 Transportation Facilities Supply and Total Revenues from contracts with customers $ 590 $ 281 $ 7,387 $ 8,258 Other items in revenues 7 10 155 172 Total revenues of reportable segments $ 597 $ 291 $ 7,542 $ 8,430 Intersegment revenues (544 ) Total revenues $ 7,886 Three Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 496 $ 285 $ 8,534 $ 9,315 Other items in revenues 2 4 (51 ) (45 ) Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ 9,270 Intersegment revenues (478 ) Total revenues $ 8,792 Nine Months Ended September 30, 2019 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,685 $ 843 $ 23,096 $ 25,624 Other items in revenues 27 37 384 448 Total revenues of reportable segments $ 1,712 $ 880 $ 23,480 $ 26,072 Intersegment revenues (1,557 ) Total revenues $ 24,515 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,416 $ 845 $ 24,832 $ 27,093 Other items in revenues 11 21 (456 ) (424 ) Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ 26,669 Intersegment revenues (1,400 ) Total revenues $ 25,269 Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. At September 30, 2019 and December 31, 2018 , counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments totaled $50 million and $62 million , respectively, of which $30 million and $40 million , respectively, was recorded as a contract liability. The remaining balance of $20 million and $22 million at September 30, 2019 and December 31, 2018 , respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts. Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the contract liability balance during the nine months ended September 30, 2019 (in millions): Contract Liabilities Balance at December 31, 2018 $ 338 Amounts recognized as revenue (226 ) Additions 82 Other (1 ) Balance at September 30, 2019 $ 193 Remaining Performance Obligations . Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2019 (in millions): Remainder of 2019 2020 2021 2022 2023 2024 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 41 $ 162 $ 171 $ 169 $ 167 $ 849 Storage, terminalling and throughput agreement revenues 114 369 270 211 176 483 Total $ 155 $ 531 $ 441 $ 380 $ 343 $ 1,332 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation: • Minimum volume commitments on certain of our joint venture pipeline systems; • Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions; • Supply and Logistics buy/sell arrangements — Contracts include agreements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems; • All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts; • Transportation and Facilities contracts that are short-term; • Contracts within the scope of ASC Topic 842, Leases ; and • Contracts within the scope of ASC Topic 815, Derivatives and Hedging . Trade Accounts Receivable and Other Receivables, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, 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). Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. 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 September 30, 2019 and December 31, 2018 , 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 September 30, 2019 and December 31, 2018 . Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheets (in millions): September 30, December 31, 2018 Trade accounts receivable arising from revenues from contracts with customers $ 2,628 $ 2,277 Other trade accounts receivables and other receivables (1) 3,076 2,732 Impact due to contractual rights of offset with counterparties (2,792 ) (2,555 ) Trade accounts receivable and other receivables, net $ 2,912 $ 2,454 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606. |
Net Income Per Class A Share
Net Income Per Class A Share | 9 Months Ended |
Sep. 30, 2019 | |
Earnings Per Share [Abstract] | |
Net Income Per Class A Share | Net Income Per Class A Share Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented. Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) certain Class B units of AAP (referred to herein as “AAP Management Units”) into our Class A shares. In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”). All AAP Management Units that have satisfied the applicable performance conditions are considered potentially dilutive. Exchanges of potentially dilutive AAP units and AAP Management Units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding exchanges of AAP units and AAP Management Units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding PAGP LTIP awards. For the three and nine months ended September 30, 2019 and 2018 , the possible exchange of any AAP units would have had an antidilutive effect on basic net income per Class A share. For the three months ended September 30, 2019 and the three and nine months ended September 30, 2018, the possible exchange of AAP Management units would not have had a dilutive effect on basic net income per Class A share. For the nine months ended September 30, 2019, the possible exchange of AAP Management Units would have had a dilutive effect on basic net income per Class A share. For the three and nine months ended September 30, 2019 and 2018 , our PAGP LTIP awards were dilutive; however, there were less than 0.1 million dilutive LTIP awards for each period, which did not change the presentation of weighted average Class A shares outstanding or net income per Class A share. The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Basic Net Income per Class A Share Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 Basic weighted average Class A shares outstanding 168 158 163 157 Basic net income per Class A share $ 0.41 $ 0.70 $ 1.73 $ 0.98 Diluted Net Income per Class A Share Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units — — 1 — Net income attributable to PAGP including incremental net income from assumed exchange of AAP Management Units $ 70 $ 111 $ 284 $ 154 Basic weighted average Class A shares outstanding 168 158 163 157 Dilutive shares resulting from assumed exchange of AAP Management Units — — 2 — Diluted weighted average Class A shares outstanding 168 158 165 157 Diluted net income per Class A share $ 0.41 $ 0.70 $ 1.72 $ 0.98 |
Inventory, Linefill and Base Ga
Inventory, Linefill and Base Gas and Long-term Inventory | 9 Months Ended |
Sep. 30, 2019 | |
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): September 30, 2019 December 31, 2018 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 11,481 barrels $ 616 $ 53.65 9,657 barrels $ 367 $ 38.00 NGL 12,449 barrels 182 $ 14.62 10,384 barrels 262 $ 25.23 Other N/A 18 N/A N/A 11 N/A Inventory subtotal 816 640 Linefill and base gas Crude oil 13,513 barrels 775 $ 57.35 13,312 barrels 761 $ 57.17 NGL 1,715 barrels 47 $ 27.41 1,730 barrels 47 $ 27.17 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 930 916 Long-term inventory Crude oil 2,587 barrels 138 $ 53.34 1,890 barrels 79 $ 41.80 NGL 1,707 barrels 21 $ 12.30 2,368 barrels 57 $ 24.07 Long-term inventory subtotal 159 136 Total $ 1,905 $ 1,692 (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. |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2019 | |
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, 2018 $ 1,040 $ 978 $ 503 $ 2,521 Foreign currency translation adjustments 7 2 2 11 Balance at September 30, 2019 $ 1,047 $ 980 $ 505 $ 2,532 We utilized a quantitative assessment in our goodwill impairment test as of June 30, 2019 and determined that there was no |
Investments in Unconsolidated E
Investments in Unconsolidated Entities | 9 Months Ended |
Sep. 30, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Entities | Investments in Unconsolidated Entities Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at Investment Balance Entity (1) Type of Operation September 30, September 30, 2019 December 31, 2018 Advantage Pipeline Holdings LLC Crude Oil Pipeline 50% $ 74 $ 72 BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% 432 435 Cactus II Pipeline LLC Crude Oil Pipeline 65% 666 455 Caddo Pipeline LLC Crude Oil Pipeline 50% 66 65 Capline Pipeline Company LLC Crude Oil Pipeline (2) 54% 462 — Cheyenne Pipeline LLC Crude Oil Pipeline 50% 44 44 Diamond Pipeline LLC Crude Oil Pipeline 50% 476 479 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 386 383 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 124 108 Midway Pipeline LLC Crude Oil Pipeline 50% 76 78 Red Oak Pipeline LLC (“Red Oak”) Crude Oil Pipeline (3) 50% 3 — Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 227 215 Settoon Towing, LLC Barge Transportation Services 50% 58 58 STACK Pipeline LLC Crude Oil Pipeline 50% 116 120 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 196 190 Wink to Webster Pipeline LLC (“W2W Pipeline”) Crude Oil Pipeline (3) 16% 79 — Total investments in unconsolidated entities $ 3,485 $ 2,702 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) The Capline pipeline was taken out of service in the fourth quarter of 2018. During the third quarter of 2019, the owners of Capline Pipeline Company LLC sanctioned the reversal of the Capline pipeline system. (3) Asset is currently under construction and has not yet been placed in service. Formations Capline LLC. During the first quarter of 2019, the owners of the Capline pipeline system, which originates in St. James, Louisiana and terminates in Patoka, Illinois, contributed their undivided joint interests in the system to a newly formed entity, Capline Pipeline Company LLC (“Capline LLC”), in exchange for equity interests in such entity. After the contribution, Capline LLC owns 100% of the pipeline system. Each owner’s undivided joint interest in the Capline pipeline system prior to the transaction is equal to each owner’s equity interest in Capline LLC. Although we own a majority of Capline LLC’s equity, we do not have a controlling financial interest in Capline LLC because the other members have substantive participating rights. Therefore, we account for our ownership interest in Capline LLC as an equity method investment. Under applicable accounting rules, the transaction resulted in a “loss of control” of our undivided joint interest, which was derecognized and contributed to Capline LLC. The “loss of control” required us to measure our equity interest in Capline LLC at fair value. At the time of the transaction, our 54% undivided joint interest in the Capline pipeline system had a carrying value of $175 million , which primarily related to property and equipment included in our Transportation segment. We determined the fair value of our investment in Capline LLC to be approximately $444 million , resulting in the recognition of a gain of $269 million during the nine months ended September 30, 2019. Such gain is included in “Gain on investment in unconsolidated entities” on our Condensed Consolidated Statement of Operations. The fair value of our investment in Capline LLC was based on an income approach utilizing a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues and expenditures. Those forecasts require the use of various assumptions and estimates which include those related to the timing and amount of capital expenditures, the expected tariff rates and volumes of crude oil, and the terminal value. These assumptions are based on a potential reversal of the Capline pipeline and the initiation of southbound service on the Capline pipeline from Patoka to St. James, and potential service on our Diamond joint venture pipeline and the Capline pipeline from Cushing, Oklahoma to St. James. We probability weighted various forecasted cash flow scenarios utilized in the analysis when we considered the possible outcomes. We used a discount rate representing our estimate of the risk adjusted discount rate that would be used by market participants. These projects are dependent upon shipper interest. If shipper interest varies from the levels assumed in our model, the related cash flows, and thus the fair value of our investment, could be materially impacted. The fair value of our investment was determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy. W2W Pipeline. In the first quarter of 2019, we announced the formation of W2W Pipeline, a joint venture with subsidiaries of ExxonMobil and Lotus Midstream, LLC. During the third quarter of 2019, three additional entities joined as partners in W2W Pipeline. As a result, our ownership interest in W2W Pipeline decreased from 20% to 16% . We account for our interest in W2W Pipeline under the equity method of accounting. W2W Pipeline is currently developing a new pipeline system that will originate in the Permian Basin in West Texas and transport crude oil to the Texas Gulf Coast. The pipeline system will provide approximately 1.5 million barrels per day of crude oil and condensate capacity, and the project is targeted to commence operations in 2021. W2W Pipeline has entered into an undivided joint-ownership arrangement with a third party whereby the third party has acquired 29% of the capacity of the pipeline segment from Midland, Texas to Webster, Texas, and W2W Pipeline now owns 71% of this segment of the pipeline. Red Oak. In June 2019, we announced the formation of Red Oak, a joint venture with a subsidiary of Phillips 66. We own a 50% interest in Red Oak, which is currently developing a new pipeline that will provide crude oil transportation service from Cushing, Oklahoma, and the Permian Basin in West Texas to Corpus Christi, Ingleside, Houston and Beaumont, Texas. Initial service from Cushing to the Gulf Coast is targeted to commence in 2021, subject to receipt of applicable permits and regulatory approvals. We account for our interest in Red Oak under the equity method of accounting. In addition to contributing cash for construction of the Red Oak pipeline system, we have also entered into a pipeline capacity lease agreement with Red Oak whereby Red Oak has agreed to lease 260,000 barrels of capacity on our Sunrise II pipeline once the Red Oak pipeline system is operational. Once the Red Oak pipeline system is operational, we will record (i) a $155 million increase to our investment in Red Oak associated with our deemed contribution of the value attributable to the capacity lease and (ii) corresponding deferred revenue that will be recognized on a straight-line basis over the initial lease term of 33 years . |
Debt
Debt | 9 Months Ended |
Sep. 30, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Debt Debt consisted of the following (in millions): September 30, December 31, SHORT-TERM DEBT PAA senior notes: 2.60% senior notes due December 2019 $ 500 $ — 5.75% senior notes due January 2020 500 — Other 84 66 Total short-term debt 1,084 66 LONG-TERM DEBT PAA senior notes, net of unamortized discounts and debt issuance costs of $63 and $59, respectively (1) 8,937 8,941 PAA GO Zone term loans, net of debt issuance costs of $1 and $2, respectively, bearing a weighted-average interest rate of 2.9% and 3.1%, respectively 199 198 Other 37 4 Total long-term debt 9,173 9,143 Total debt (2) $ 10,257 $ 9,209 (1) As of December 31, 2018 , we classified PAA’s $500 million , 2.60% senior notes due December 2019 as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis. (2) PAA’s fixed-rate senior notes had a face value of approximately $10.0 billion and $9.0 billion at September 30, 2019 and December 31, 2018 , respectively. We estimated the aggregate fair value of these notes as of September 30, 2019 and December 31, 2018 to be approximately $10.3 billion and $8.6 billion , respectively. PAA’s 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 PAA’s credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Credit Facilities In August 2019, PAA extended the maturity dates of its senior unsecured revolving credit facility and senior secured hedged inventory facility by one year to August 2024 and August 2022, respectively, for each extending lender. Borrowings and Repayments Total borrowings under the PAA credit facilities and commercial paper program for the nine months ended September 30, 2019 and 2018 were approximately $10.5 billion and $38.6 billion , respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $10.5 billion and $39.2 billion for the nine months ended September 30, 2019 and 2018 , respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2019 and December 31, 2018 , we had outstanding letters of credit of $149 million and $184 million , respectively. Senior Notes In September 2019, PAA completed the issuance of $1.0 billion , 3.55% senior notes due December 20 29 at a public offering price of 99.801% . Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2020. In October 2019, PAA sent notice to the holders of its $500 million , 2.60% senior notes due December 2019 that it will redeem the notes on November 15, 2019. |
Partners' Capital and Distribut
Partners' Capital and Distributions | 9 Months Ended |
Sep. 30, 2019 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital and Distributions | Partners’ Capital and Distributions Shares Outstanding The following tables present the activity for our Class A shares, Class B shares and Class C shares: Class A Shares Class B Shares Class C Shares Outstanding at December 31, 2018 159,485,588 119,604,338 516,938,280 Redemption Right exercises (1) — (91,672 ) 91,672 Other — — 226,814 Outstanding at March 31, 2019 159,485,588 119,512,666 517,256,766 Exchange Right exercises (1) 7,331,745 (7,331,745 ) — Redemption Right exercises (1) — (12,193,771 ) 12,193,771 Other — — 603,456 Outstanding at June 30, 2019 166,817,333 99,987,150 530,053,993 Exchange Right exercises (1) 15,173,490 (15,173,490 ) — Redemption Right exercises (1) — (16,254,598 ) 16,254,598 Other 15,186 — 588,771 Outstanding at September 30, 2019 182,006,009 68,559,062 546,897,362 Class A Shares Class B Shares Class C Shares Outstanding at December 31, 2017 156,111,139 126,984,572 510,925,432 Exchange Right exercises (1) 907,899 (907,899 ) — Redemption Right exercises (1) (39,224 ) 39,224 Issuance of Series A preferred units by a subsidiary — — 1,393,926 Other — — 17,766 Outstanding at March 31, 2018 157,019,038 126,037,449 512,376,348 Exchange Right exercises (1) 935,092 (935,092 ) — Redemption Right exercises (1) — (3,084,027 ) 3,084,027 Outstanding at June 30, 2018 157,954,130 122,018,330 515,460,375 Exchange Right exercises (1) 1,195,405 (1,195,405 ) — Redemption Right exercises (1) — (183,225 ) 183,225 Other 11,250 — 494,400 Outstanding at September 30, 2018 159,160,785 120,639,700 516,138,000 (1) See Note 12 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding Exchange Rights and Redemption Rights. Exchange Right and Redemption Right Exercises During the nine months ended September 30, 2019, an affiliate of The Energy & Minerals Group (“EMG”) and a subsidiary of Occidental Petroleum Corporation (“Oxy”) exercised their Exchange Right and Redemption Right. The Redemption Right exercises resulted in the issuance of additional Class C shares to PAA. The Exchange Right exercises resulted in the transfer of a portion of partners’ capital from noncontrolling interests to our Class A shareholders and the associated recognition of a deferred tax asset that was recorded as a component of partners’ capital as it resulted from transactions with shareholders. Distributions The following table details distributions to our Class A shareholders paid during or pertaining to the first nine months of 2019 (in millions, except per share data): Distribution Payment Date Distributions to Class A Shareholders Distributions per Class A Share November 14, 2019 (1) $ 66 $ 0.36 August 14, 2019 $ 60 $ 0.36 May 15, 2019 $ 57 $ 0.36 February 14, 2019 $ 48 $ 0.30 (1) Payable to shareholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . Consolidated Subsidiaries Noncontrolling Interests in Subsidiaries As of September 30, 2019 , noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 68% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 27% limited partner interest in AAP and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”), as discussed further below. In May 2019, we formed a joint venture, Red River LLC, with Delek Logistics Partners, LP (“Delek”) on our Red River pipeline system. We received approximately $128 million for Delek’s 33% interest in Red River LLC. We consolidate Red River LLC, with Delek’s 33% interest accounted for as a noncontrolling interest. Subsidiary Distributions PAA Series A Preferred Unit Distributions . The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first nine months of 2019 (in millions, except per unit data): Series A Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 14, 2019 (1) $ 37 $ 0.525 August 14, 2019 $ 37 $ 0.525 May 15, 2019 $ 37 $ 0.525 February 14, 2019 $ 37 $ 0.525 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . At September 30, 2019 , such amount was accrued to distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet. PAA Series B Preferred Unit Distributions . Distributions on PAA’s Series B preferred units are payable semi-annually in arrears on the 15th day of May and November. The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders during the first nine months of 2019 (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 15, 2019 (1) $ 24.5 $ 30.625 May 15, 2019 $ 24.5 $ 30.625 (1) Payable to unitholders of record at the close of business on November 1, 2019 for the period from May 15, 2019 through November 14, 2019. As of September 30, 2019 , we had accrued approximately $18 million of distributions payable to PAA’s Series B preferred unitholders in “Other current liabilities” on our Condensed Consolidated Balance Sheet. PAA Common Unit Distributions. The following table details distributions to PAA’s common unitholders paid during or pertaining to the first nine months of 2019 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP November 14, 2019 (1) $ 171 $ 91 $ 262 $ 0.36 August 14, 2019 $ 166 $ 96 $ 262 $ 0.36 May 15, 2019 $ 161 $ 101 $ 262 $ 0.36 February 14, 2019 $ 134 $ 84 $ 218 $ 0.30 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first nine months of 2019 from distributions received from PAA (in millions): Distribution to AAP ’ s Partners Distribution Payment Date Noncontrolling Interests PAGP Total Cash Distributions November 14, 2019 (1) $ 25 $ 66 $ 91 August 14, 2019 $ 36 $ 60 $ 96 May 15, 2019 $ 44 $ 57 $ 101 February 14, 2019 $ 36 $ 48 $ 84 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . During the nine months ended September 30, 2019 , distributions of $4 million |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 9 Months Ended |
Sep. 30, 2019 | |
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. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis. 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 sales 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 September 30, 2019 , net derivative positions related to these activities included: • A net long position of 3.1 million barrels associated with our crude oil purchases, which was unwound ratably during October 2019 to match monthly average pricing. • A net short time spread position of 6.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2020 . • A net crude oil basis spread position of 23.1 million barrels at multiple locations through December 2021 . These derivatives allow us to lock in grade basis differentials. • A net short position of 12.1 million barrels through December 2021 related to anticipated net sales of crude oil and NGL inventory. Storage Capacity Utilization — For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of September 30, 2019 , we used derivatives to manage the risk that a portion of our storage capacity will not be utilized (an average of approximately 0.9 million barrels per month of storage capacity through January 2021 ). These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil. 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. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of September 30, 2019 : Notional Volume (Short)/Long Remaining Tenor Natural gas purchases 59.5 Bcf December 2022 Propane sales (5.7) MMbls March 2021 Butane sales (2.7) MMbls March 2021 Condensate sales (WTI position) (0.7) MMbls March 2021 Specification products sales (put option) 0.1 MMbls March 2020 Power supply requirements (1) 1.0 TWh December 2022 (1) Power position to hedge a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate associated 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 expense associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2019 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting Anticipated interest payments 8 forward starting swaps $ 200 6/15/2020 3.06 % Cash flow hedge Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. Our use of foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements. The following table summarizes our open forward exchange contracts as of September 30, 2019 (in millions): USD CAD Average Exchange Rate Forward exchange contracts that exchange CAD for USD: 2019 $ 42 $ 56 $1.00 - $1.32 Forward exchange contracts that exchange USD for CAD: 2019 $ 98 $ 130 $1.00 - $1.32 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 the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA 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. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for additional information regarding the Series A preferred units and 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 designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that are not designated as a hedging instrument and derivatives that do not qualify for hedge accounting 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 derivatives recognized in earnings is as follows (in millions): Three Months Ended September 30, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 149 $ (1 ) $ — $ — $ 148 Field operating costs (1) 4 — — — 4 Interest expense, net (2) — — — (2 ) (2 ) Other income/(expense), net (1) — — 1 — 1 Total gain/(loss) on derivatives recognized in net income $ 153 $ (1 ) $ 1 $ (2 ) $ 151 Three Months Ended September 30, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (59 ) $ 5 $ — $ — $ (54 ) Field operating costs (1) (1 ) — — — (1 ) Interest expense, net (2) — — — (2 ) (2 ) Other income/(expense), net (1) — — (2 ) — (2 ) Total gain/(loss) on derivatives recognized in net income $ (60 ) $ 5 $ (2 ) $ (2 ) $ (59 ) Nine Months Ended September 30, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 380 $ 6 $ — $ — $ 386 Field operating costs (1) 15 — — — 15 Interest expense, net (2) — — — (7 ) (7 ) Other income/(expense), net (1) — — 16 — 16 Total gain/(loss) on derivatives recognized in net income $ 395 $ 6 $ 16 $ (7 ) $ 410 Nine Months Ended September 30, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (443 ) $ (7 ) $ — $ — $ (450 ) Field operating costs (1) — — — — — Interest expense, net (2) — — — (3 ) (3 ) Other income/(expense), net (1) — — 3 — 3 Total gain/(loss) on derivatives recognized in net income $ (443 ) $ (7 ) $ 3 $ (3 ) $ (450 ) (1) Derivatives not designated as a hedge. (2) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2019 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 376 $ — $ — $ 376 $ — $ 376 Other long-term assets, net 59 — — 59 — 59 Other current liabilities 2 — — 2 — 2 Total Derivative Assets $ 437 $ — $ — $ 437 $ — $ 437 Derivative Liabilities Other current assets $ (67 ) $ — $ — $ (67 ) $ — $ (67 ) Other long-term assets, net (5 ) — — (5 ) — (5 ) Other current liabilities (14 ) (1 ) — (15 ) (64 ) (79 ) Other long-term liabilities and deferred credits (14 ) — (19 ) (33 ) — (33 ) Total Derivative Liabilities $ (100 ) $ (1 ) $ (19 ) $ (120 ) $ (64 ) $ (184 ) (1) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2018 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 441 $ — $ — $ 441 $ 2 $ 443 Other long-term assets, net 34 — — 34 — 34 Other long-term liabilities and deferred credits 3 — — 3 — 3 Total Derivative Assets $ 478 $ — $ — $ 478 $ 2 $ 480 Derivative Liabilities Other current assets $ (182 ) $ — $ — $ (182 ) $ — $ (182 ) Other long-term assets, net (7 ) — — (7 ) — (7 ) Other current liabilities (10 ) (9 ) — (19 ) (1 ) (20 ) Other long-term liabilities and deferred credits (9 ) — (36 ) (45 ) (8 ) (53 ) Total Derivative Liabilities $ (208 ) $ (9 ) $ (36 ) $ (253 ) $ (9 ) $ (262 ) (1) Derivatives in hedging relationships. Our financial derivatives, used for hedging risk, are governed through ISDA 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): September 30, December 31, Initial margin $ 96 $ 95 Variation margin returned (131 ) (91 ) Letters of credit (75 ) (84 ) Net broker payable $ (110 ) $ (80 ) The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): September 30, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 437 $ (184 ) $ 480 $ (262 ) Netting adjustment (74 ) 74 (192 ) 192 Cash collateral received (110 ) — (80 ) — Net position - asset/(liability) $ 253 $ (110 ) $ 208 $ (70 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 199 $ — $ 181 $ — Other long-term assets, net 54 — 27 — Other current liabilities — (77 ) — (20 ) Other long-term liabilities and deferred credits — (33 ) — (50 ) $ 253 $ (110 ) $ 208 $ (70 ) As of September 30, 2019 , there was a net loss of $281 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 transactions or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at September 30, 2019 , we expect to reclassify a net loss of $10 million to earnings in the next twelve months. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2050 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of September 30, 2019 ; 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 unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Interest rate derivatives, net $ (53 ) $ 15 $ (111 ) $ 60 At September 30, 2019 and December 31, 2018 , 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 PAA’s 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 September 30, 2019 Fair Value as of December 31, 2018 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 167 $ 190 $ (20 ) $ 337 $ 171 $ 87 $ 12 $ 270 Interest rate derivatives — (64 ) — (64 ) — (7 ) — (7 ) Foreign currency derivatives — (1 ) — (1 ) — (9 ) — (9 ) Preferred Distribution Rate Reset Option — — (19 ) (19 ) — — (36 ) (36 ) Total net derivative asset/(liability) $ 167 $ 125 $ (39 ) $ 253 $ 171 $ 71 $ (24 ) $ 218 (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 and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts 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 observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity and other contracts, over-the-counter options and the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which is classified as an embedded derivative. The fair values of our Level 3 physical commodity and other contracts and over-the-counter options are based on valuation models utilizing significant timing estimates, which involve management judgment, and pricing inputs from observable and unobservable markets with less volume and transaction frequency than active markets. Significant deviations from these estimates and inputs could result in a material change in fair value. We report unrealized gains and losses associated with these contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. The fair value of the embedded derivative feature contained in PAA’s partnership agreement is based on a valuation model that estimates the fair value of the PAA Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including PAA’s common unit price, ten-year U.S. Treasury rates, default probabilities and timing estimates, some of which involve management judgment. A significant change in 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 in “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 Nine Months Ended 2019 2018 2019 2018 Beginning Balance $ (26 ) $ (18 ) $ (24 ) $ (30 ) Net gains/(losses) for the period included in earnings 4 (5 ) 21 2 Settlements 1 — (10 ) 7 Derivatives entered into during the period (18 ) — (26 ) (2 ) Ending Balance $ (39 ) $ (23 ) $ (39 ) $ (23 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (14 ) $ (5 ) $ (5 ) $ — |
Leases
Leases | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Lessor, Operating Leases | Lessor We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the three and nine months ended September 30, 2019 , our lease revenue was not material. The table below presents the maturity of lease payments for operating lease agreements in effect as of September 30, 2019 . This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 23 years . The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): Remainder 2020 2021 2022 2023 Thereafter Lease revenue $ 5 $ 19 $ 22 $ 25 $ 21 $ 226 |
Lessee, Finance Leases | Leases Lessee We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, vehicles and land. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years . When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date. The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Three Months Ended Nine Months Ended Operating lease cost $ 32 $ 95 Short-term lease cost 11 32 Other (1) (1 ) — Total lease cost $ 42 $ 127 (1) Includes immaterial finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Nine Months Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 101 Financing cash flows for finance leases $ 13 Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications: Operating leases $ 16 Finance leases $ 10 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: September 30, 2019 Weighted-average remaining lease term (in years): Operating leases 10.2 Finance leases 3.6 Weighted-average discount rate: Operating leases 4.5% Finance leases 2.4% The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Condensed Consolidated Balance Sheet (in millions): Leases Balance Sheet Location September 30, 2019 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 443 Finance lease right-of-use assets Property and equipment $ 110 Accumulated depreciation (15 ) Property and equipment, net $ 95 Total lease right-of-use assets $ 538 Liabilities Operating lease liabilities Current Other current liabilities $ 103 Noncurrent Long-term operating lease liabilities 348 Total operating lease liabilities $ 451 Finance lease liabilities Current Short-term debt $ 19 Noncurrent Other long-term debt, net 37 Total finance lease liabilities $ 56 Total lease liabilities $ 507 The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of September 30, 2019 reconciled to our lease liabilities on our Condensed Consolidated Balance Sheet (amounts in millions): Operating Finance Future minimum lease payments (1) : Remainder of 2019 $ 31 $ 5 2020 113 18 2021 93 9 2022 78 10 2023 54 7 Thereafter 247 10 Total 616 59 Less: Present value discount (165 ) (3 ) Lease liabilities $ 451 $ 56 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet. |
Lessee, Operating Leases | Leases Lessee We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, vehicles and land. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years . When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date. The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Three Months Ended Nine Months Ended Operating lease cost $ 32 $ 95 Short-term lease cost 11 32 Other (1) (1 ) — Total lease cost $ 42 $ 127 (1) Includes immaterial finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Nine Months Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 101 Financing cash flows for finance leases $ 13 Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications: Operating leases $ 16 Finance leases $ 10 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: September 30, 2019 Weighted-average remaining lease term (in years): Operating leases 10.2 Finance leases 3.6 Weighted-average discount rate: Operating leases 4.5% Finance leases 2.4% The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Condensed Consolidated Balance Sheet (in millions): Leases Balance Sheet Location September 30, 2019 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 443 Finance lease right-of-use assets Property and equipment $ 110 Accumulated depreciation (15 ) Property and equipment, net $ 95 Total lease right-of-use assets $ 538 Liabilities Operating lease liabilities Current Other current liabilities $ 103 Noncurrent Long-term operating lease liabilities 348 Total operating lease liabilities $ 451 Finance lease liabilities Current Short-term debt $ 19 Noncurrent Other long-term debt, net 37 Total finance lease liabilities $ 56 Total lease liabilities $ 507 The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of September 30, 2019 reconciled to our lease liabilities on our Condensed Consolidated Balance Sheet (amounts in millions): Operating Finance Future minimum lease payments (1) : Remainder of 2019 $ 31 $ 5 2020 113 18 2021 93 9 2022 78 10 2023 54 7 Thereafter 247 10 Total 616 59 Less: Present value discount (165 ) (3 ) Lease liabilities $ 451 $ 56 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet. |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions See Note 16 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for a complete discussion of our related party transactions. PAA ’ s Ownership of our Class C Shares As of September 30, 2019 and December 31, 2018 , PAA owned 546,897,362 and 516,938,280 , respectively, Class C shares. The Class C shares represent a non-economic limited partner interest in us that provides PAA, as the sole holder, a “pass-through” voting right through which PAA’s common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible directors. Transactions with Other Related Parties Our other related parties include (i) principal owners and their affiliated entities and (ii) entities in which we hold investments and account for under the equity method of accounting (see Note 7 for additional information regarding such entities). We recognize as our principal owners entities that have a designated representative on the board of directors of our general partner and/or own greater than 10% of the limited partner interests in AAP. Such limited partner interests in AAP translates into a significantly smaller indirect ownership interest in PAA. We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties. As of September 30, 2019, Kayne Anderson Capital Advisors, L.P. was a principal owner. Through various transactions by EMG in May 2019, EMG’s limited partner interest in AAP was significantly reduced, which caused EMG to lose its right to designate a representative on the board of directors of our general partner. As a result, EMG’s board designee, John T. Raymond, was automatically removed from the board of directors of our general partner. Subsequent to such removal, Mr. Raymond was elected to continue to serve as a director of the board. Additionally, as a result of various transactions by Oxy in September 2019, Oxy no longer holds a limited partner interest in AAP and lost its right to designate a representative on the board of directors of our general partner. As a result, Oxy’s board designee, Oscar Brown, was automatically removed from the board of directors of our general partner. Following these transactions, we no longer recognize EMG or Oxy as a principal owner. During the three and nine months ended September 30, 2019 and 2018 , we recognized sales and transportation revenues, purchased petroleum products and utilized transportation services from our principal owners and their affiliated entities and our equity method investees. 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 these transactions is included below (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Revenues from related parties (1) (2) $ 205 $ 266 $ 661 $ 832 Purchases and related costs from related parties (2) $ (7 ) $ 157 $ 93 $ 317 (1) A majority of these revenues are included in “Supply and Logistics segment revenues” on our Condensed Consolidated Statements of Operations. (2) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations. Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions): September 30, December 31, Trade accounts receivable and other receivables, net from related parties (1) (2) $ 165 $ 144 Trade accounts payable to related parties (1) (2) (3) $ 105 $ 121 (1) We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts. (2) Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager. (3) We have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2019 | |
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 September 30, 2019 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $135 million , of which $62 million was classified as short-term and $73 million was classified as long-term. At December 31, 2018 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $135 million , of which $43 million was classified as short-term and $92 million was classified as long-term. Such short- and long-term environmental liabilities are reflected in “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At September 30, 2019 , we had recorded receivables totaling $62 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $31 million was classified as short-term and $31 million was classified as long-term. At December 31, 2018 , we had recorded $61 million of such receivables, of which $28 million was classified as short-term and $33 million was classified as long-term. Such short- and long-term receivables are reflected in “Trade accounts receivable and other receivables, net” and “Other long-term assets, net,” respectively, on our Condensed Consolidated Balance Sheets. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident . In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), 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 12, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station, which was subsequently lifted, and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in service. 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 brought any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we are likely to have fines or penalties imposed upon us, and civil charges brought against us, in the future. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara (collectively, the “Prosecutors”) began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of 46 counts against PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018, 31 of the criminal charges against PAA (including one felony charge) and all of the criminal charges against our employee, were dismissed. The remaining 15 charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. The jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The jury deadlocked on three counts (including two felony discharge counts and one strict liability animal takings count), and two misdemeanor discharge counts were dropped. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. The Superior Court also indicated that it would conduct further hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. We do not anticipate that the victim restitution, if any, imposed as a result of these proceedings will have a material adverse impact on the financial position or operations of the Partnership. In April of 2019, the Prosecutors announced their intent to re-try the two felony discharge counts for which no jury verdict was returned. The strict liability animal taking count for which no jury verdict was returned has been dismissed. On October 7, 2019, upon motion from Plains, the court dismissed the two remaining felony counts and vacated a second trial on these 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 have cooperated with the DOJ’s investigation by responding to their requests for documents and access to our 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. Except in connection with the May 2016 Indictment and the 2019 Sentence, to date no civil enforcement actions or criminal charges with respect to the Line 901 release have been brought against PAA or any of its affiliates, officers or employees by PHMSA, the DOJ, the EPA, the California Attorney General or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies; however, 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 in the future, or civil actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we have been processing those claims and making payments as appropriate. In addition, we have also had nine class action lawsuits filed against us, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. To date, the court has certified three sub-classes of claimants and denied certification of the other proposed sub-class. On appeal, the Ninth Circuit Court of Appeals overturned the certification of the oil-industry sub-class, so the remaining sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; and (ii) beachfront property and easement owners whose properties were oiled. 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 were also two securities law class action lawsuits filed on behalf of certain purported investors in PAA and/or PAGP against PAA, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits were consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits alleged that the various defendants violated securities laws by misleading investors regarding the integrity of PAA’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 claimed unspecified damages as a result of the reduction in value of their investments in PAA and PAGP, which they attributed to the alleged wrongful acts of the defendants. PAA 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 refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs appealed the dismissal, and on July 16, 2019 the Fifth Circuit Court of Appeals affirmed the dismissal. The time period for a further appeal to the U.S. Supreme Court has lapsed so this ruling is now final. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we also indemnified and funded 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 PAA against PAA, certain of its affiliates and certain officers and directors. One lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. 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 and subsequently dismissed without prejudice. Plaintiffs amended and refiled their complaint on June 3, 2019. 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 received several other individual lawsuits and complaints from companies, governmental agencies 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. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the following federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”): the United States Department of Interior, the National Oceanic and Atmospheric Administration, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, and the Regents of the University of California. As part of the NRDA process, PAA and the Trustees jointly and independently planned and conducted a number of natural resource assessment activities related to the Line 901 incident. We are currently involved in discussions with the Trustees to determine the amount we will be required to pay as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. We also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. We are actively involved in discussions with the relevant federal and state agencies to determine the amount of such fines, penalties and costs, and we have included an estimate of such costs in the loss accrual described below. To the extent any unpaid natural resource damages or other fines, penalties or 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 September 30, 2019 , we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $380 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 accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable or 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 September 30, 2019 , we had a remaining undiscounted gross liability of $79 million related to this event, of which approximately $52 million is presented in “Other current 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 September 30, 2019 , we had collected, subject to customary reservations, $200 million out of the approximate $255 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of September 30, 2019 , we have recognized a receivable of approximately $55 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 $26 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. San Joaquin Valley Air Pollution Control District. After conducting inspections of the Plains LPG Services, L.P. (“Plains LPG”) facility in Shafter, California during March and June of 2018, the San Joaquin Valley Air Pollution Control District (the “District”) issued four Notices of Violation which totaled $597,000 in the aggregate. Plains LPG entered into a settlement with the District whereby Plains LPG agreed to enter the District’s INSPECT program (a self-reporting and inspection program) and pay a reduced fine of $275,000 , which was paid in July 2019. |
Operating Segments
Operating Segments | 9 Months Ended |
Sep. 30, 2019 | |
Segment Reporting [Abstract] | |
Operating Segments | Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. 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, and gains and losses on significant asset sales by, unconsolidated entities, and further adjusted for certain selected items including (i) gains and 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 and/or refurbishment 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 September 30, 2019 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 319 $ 149 $ 7,541 $ (123 ) $ 7,886 Intersegment (2) 278 142 1 123 544 Total revenues of reportable segments $ 597 $ 291 $ 7,542 $ — $ 8,430 Equity earnings in unconsolidated entities $ 102 $ — $ — $ 102 Segment Adjusted EBITDA $ 462 $ 173 $ 92 $ 727 Maintenance capital $ 42 $ 28 $ 15 $ 85 Three Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 292 $ 149 $ 8,482 $ (131 ) $ 8,792 Intersegment (2) 206 140 1 131 478 Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ — $ 9,270 Equity earnings in unconsolidated entities $ 110 $ — $ — $ 110 Segment Adjusted EBITDA $ 388 $ 173 $ 75 $ 636 Maintenance capital $ 41 $ 33 $ 4 $ 78 Nine Months Ended September 30, 2019 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 938 $ 457 $ 23,477 $ (357 ) $ 24,515 Intersegment (2) 774 423 3 357 1,557 Total revenues of reportable segments $ 1,712 $ 880 $ 23,480 $ — $ 26,072 Equity earnings in unconsolidated entities $ 274 $ — $ — $ 274 Segment Adjusted EBITDA $ 1,271 $ 529 $ 571 $ 2,371 Maintenance capital $ 110 $ 74 $ 20 $ 204 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 808 $ 437 $ 24,374 $ (350 ) $ 25,269 Intersegment (2) 619 429 2 350 1,400 Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ — $ 26,669 Equity earnings in unconsolidated entities $ 281 $ — $ — $ 281 Segment Adjusted EBITDA $ 1,083 $ 530 $ 120 $ 1,733 Maintenance capital $ 102 $ 74 $ 10 $ 186 (1) Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2018 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 revenues from External customers presented above and adjusted those revenues out such that Total revenues 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 activities are conducted at posted tariff rates where applicable, or otherwise at 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 PAGP (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Segment Adjusted EBITDA $ 727 $ 636 $ 2,371 $ 1,733 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (18 ) (15 ) (45 ) (44 ) Gains/(losses) from derivative activities, net of inventory valuation adjustments (3) 29 110 60 (107 ) Long-term inventory costing adjustments (4) 1 10 (3 ) 18 Deficiencies under minimum volume commitments, net (5) 4 4 10 (9 ) Equity-indexed compensation expense (6) (5 ) (14 ) (13 ) (37 ) Net gain/(loss) on foreign currency revaluation (7) 5 3 (7 ) (5 ) Line 901 incident (8) — — (10 ) — Unallocated general and administrative expenses (1 ) (1 ) (4 ) (3 ) Depreciation and amortization (157 ) (129 ) (441 ) (386 ) Gains/(losses) on asset sales and asset impairments, net 7 (2 ) 7 79 Gain on investment in unconsolidated entities 4 210 271 210 Interest expense, net (108 ) (110 ) (311 ) (327 ) Other income/(expense), net 5 (3 ) 23 8 Income before tax 493 699 1,908 1,130 Income tax expense (62 ) (23 ) (137 ) (84 ) Net income 431 676 1,771 1,046 Net income attributable to noncontrolling interests (361 ) (565 ) (1,488 ) (892 ) Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of, and gains and losses on significant asset sales by, unconsolidated entities. (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 PAA common units. (7) Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 13 for additional information regarding the Line 901 incident. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Canadian Provincial Taxes All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S. income tax purposes) and that are subject to Canadian federal and provincial taxes. During the second quarter of 2019, the Alberta government enacted legislation that reduces the Alberta provincial corporate income tax rate from 12% to 8% over the period from July 1, 2019 through January 1, 2022. As a result, during the second quarter of 2019, we recognized a reduction of our deferred income tax liability of approximately $60 million and a corresponding deferred tax benefit. Exchange Right Exercises As a result of the exchange of the ownership interests in AAP by EMG and Oxy during the nine months ended September 30, 2019, we recognized a deferred tax asset. See Note 9 for additional information regarding these transactions. See Note 14 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding the recognition of deferred tax assets associated with Exchange Right exercises. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
Accounting Policies [Abstract] | |
Restricted Cash | Restricted Cash |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Except as discussed below and in our 2018 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2019 that are of significance or potential significance to us. Accounting Standards Updates Adopted During the Period In February 2016, the FASB issued ASU 2016-02, Leases , (followed by a series of related accounting standard updates (collectively referred to as “Topic 842”)), that revises the historical accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of right-of-use assets and lease liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance became effective for interim and annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019. Our adoption resulted in the recording of additional net lease right-of-use assets and lease liabilities of approximately $560 million and $570 million , respectively, on January 1, 2019 and did not have a material impact on our results of operations or cash flows. We elected the package of practical expedients permitted under the transition guidance within Topic 842, which, among other things, allowed us to carry forward the historical accounting related to lease identification, classification and indirect costs. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements (including rights of way) on existing agreements. Additionally, we elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee and for all classes of assets where we are the lessor. Further, we elected the practical expedient which provides us with an optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods and, if necessary, recognizing a cumulative-effect adjustment to the opening balance of Partners’ Capital upon adoption. There was no impact to retained earnings related to our adoption. We did not elect the practical expedient related to using hindsight in determining the lease term as this was not relevant following our election of the optional transitional method. We implemented a process to evaluate the impact of adopting this guidance on each type of lease contract we have entered into with counterparties. Our implementation team determined appropriate changes to our business processes, systems and controls to support recognition and disclosure under Topic 842. In addition to the above, which primarily relates to our accounting as a lessee, our accounting from a lessor perspective remains substantially unchanged under Topic 842. See Note 11 for information about our leases. We also adopted the ASUs listed below effective January 1, 2019 and our adoption did not have a material impact to our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for additional information regarding these ASUs): • ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes; • ASU 2018-09, Codification Improvements; • ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting; and • ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Accounting Standards Updates Issued During the Period In July 2019, the FASB issued 2019-07, Codification Updates to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates , which amended SEC paragraphs in the ASC to reflect the SEC final rule releases Disclosure Update and Simplification, Investment Company Reporting Modernization and other miscellaneous updates. This guidance is effective upon issuance and did not have a material impact on our financial position, results of operations or cash flows. In May 2019, the FASB issued 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief , which provides transition relief and allows entities to elect the fair value option on certain financial instruments. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption will have on our financial position, results of operations and cash flows. In April 2019, the FASB issued 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments , which clarifies certain aspects of accounting for credit losses, hedging activities and financial instruments. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption will have on our financial position, results of operations and cash flows. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Accounting Policies [Abstract] | |
Reconciliation of Cash and Cash Equivalents and Restricted Cash | The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Condensed Consolidated Balance Sheet that sum to the total of the amounts shown on our Condensed Consolidated Statement of Cash Flows as of the end of the period (in millions): September 30, Cash and cash equivalents $ 611 Restricted cash 59 Total cash and cash equivalents and restricted cash $ 670 |
Revenues and Accounts Receiva_2
Revenues and Accounts Receivable (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Disaggregation of Revenue [Line Items] | |
Disaggregation of Revenue | The following tables present the reconciliation of our revenues from contracts with customers to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions): Three Months Ended September 30, 2019 Transportation Facilities Supply and Total Revenues from contracts with customers $ 590 $ 281 $ 7,387 $ 8,258 Other items in revenues 7 10 155 172 Total revenues of reportable segments $ 597 $ 291 $ 7,542 $ 8,430 Intersegment revenues (544 ) Total revenues $ 7,886 Three Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 496 $ 285 $ 8,534 $ 9,315 Other items in revenues 2 4 (51 ) (45 ) Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ 9,270 Intersegment revenues (478 ) Total revenues $ 8,792 Nine Months Ended September 30, 2019 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,685 $ 843 $ 23,096 $ 25,624 Other items in revenues 27 37 384 448 Total revenues of reportable segments $ 1,712 $ 880 $ 23,480 $ 26,072 Intersegment revenues (1,557 ) Total revenues $ 24,515 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,416 $ 845 $ 24,832 $ 27,093 Other items in revenues 11 21 (456 ) (424 ) Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ 26,669 Intersegment revenues (1,400 ) Total revenues $ 25,269 |
Contracts with customers, change in contract liability balance | The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheets (in millions): September 30, December 31, 2018 Trade accounts receivable arising from revenues from contracts with customers $ 2,628 $ 2,277 Other trade accounts receivables and other receivables (1) 3,076 2,732 Impact due to contractual rights of offset with counterparties (2,792 ) (2,555 ) Trade accounts receivable and other receivables, net $ 2,912 $ 2,454 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606. nine months ended September 30, 2019 (in millions): Contract Liabilities Balance at December 31, 2018 $ 338 Amounts recognized as revenue (226 ) Additions 82 Other (1 ) Balance at September 30, 2019 $ 193 |
Remaining Performance Obligations | The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2019 (in millions): Remainder of 2019 2020 2021 2022 2023 2024 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 41 $ 162 $ 171 $ 169 $ 167 $ 849 Storage, terminalling and throughput agreement revenues 114 369 270 211 176 483 Total $ 155 $ 531 $ 441 $ 380 $ 343 $ 1,332 (1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate. |
Supply and Logistics | |
Disaggregation of Revenue [Line Items] | |
Disaggregation of Revenue | The following tables present our Supply and Logistics segment, Transportation segment and Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 7,185 $ 7,978 $ 21,716 $ 22,651 NGL and other transactions 202 556 1,380 2,181 Total Supply and Logistics segment revenues from contracts with customers $ 7,387 $ 8,534 $ 23,096 $ 24,832 |
Transportation | |
Disaggregation of Revenue [Line Items] | |
Disaggregation of Revenue | Three Months Ended Nine Months Ended 2019 2018 2019 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 532 $ 435 $ 1,504 $ 1,237 NGL pipelines 25 25 75 76 Total tariff activities 557 460 1,579 1,313 Trucking 33 36 106 103 Total Transportation segment revenues from contracts with customers $ 590 $ 496 $ 1,685 $ 1,416 |
Facilities | |
Disaggregation of Revenue [Line Items] | |
Disaggregation of Revenue | Three Months Ended Nine Months Ended 2019 2018 2019 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 174 $ 174 $ 523 $ 511 NGL and natural gas processing and fractionation 87 87 262 278 Rail load / unload 20 24 58 56 Total Facilities segment revenues from contracts with customers $ 281 $ 285 $ 843 $ 845 |
Net Income Per Class A Share (T
Net Income Per Class A Share (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Earnings Per Share [Abstract] | |
Calculation of basic and diluted net income per Class A share | The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Basic Net Income per Class A Share Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 Basic weighted average Class A shares outstanding 168 158 163 157 Basic net income per Class A share $ 0.41 $ 0.70 $ 1.73 $ 0.98 Diluted Net Income per Class A Share Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units — — 1 — Net income attributable to PAGP including incremental net income from assumed exchange of AAP Management Units $ 70 $ 111 $ 284 $ 154 Basic weighted average Class A shares outstanding 168 158 163 157 Dilutive shares resulting from assumed exchange of AAP Management Units — — 2 — Diluted weighted average Class A shares outstanding 168 158 165 157 Diluted net income per Class A share $ 0.41 $ 0.70 $ 1.72 $ 0.98 |
Inventory, Linefill and Base _2
Inventory, Linefill and Base Gas and Long-term Inventory (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
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): September 30, 2019 December 31, 2018 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 11,481 barrels $ 616 $ 53.65 9,657 barrels $ 367 $ 38.00 NGL 12,449 barrels 182 $ 14.62 10,384 barrels 262 $ 25.23 Other N/A 18 N/A N/A 11 N/A Inventory subtotal 816 640 Linefill and base gas Crude oil 13,513 barrels 775 $ 57.35 13,312 barrels 761 $ 57.17 NGL 1,715 barrels 47 $ 27.41 1,730 barrels 47 $ 27.17 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 930 916 Long-term inventory Crude oil 2,587 barrels 138 $ 53.34 1,890 barrels 79 $ 41.80 NGL 1,707 barrels 21 $ 12.30 2,368 barrels 57 $ 24.07 Long-term inventory subtotal 159 136 Total $ 1,905 $ 1,692 (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. |
Goodwill (Tables)
Goodwill (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
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, 2018 $ 1,040 $ 978 $ 503 $ 2,521 Foreign currency translation adjustments 7 2 2 11 Balance at September 30, 2019 $ 1,047 $ 980 $ 505 $ 2,532 |
Investments in Unconsolidated_2
Investments in Unconsolidated Entities (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of investments in unconsolidated entities | Our investments in unconsolidated entities consisted of the following (in millions, except percentage data): Ownership Interest at Investment Balance Entity (1) Type of Operation September 30, September 30, 2019 December 31, 2018 Advantage Pipeline Holdings LLC Crude Oil Pipeline 50% $ 74 $ 72 BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% 432 435 Cactus II Pipeline LLC Crude Oil Pipeline 65% 666 455 Caddo Pipeline LLC Crude Oil Pipeline 50% 66 65 Capline Pipeline Company LLC Crude Oil Pipeline (2) 54% 462 — Cheyenne Pipeline LLC Crude Oil Pipeline 50% 44 44 Diamond Pipeline LLC Crude Oil Pipeline 50% 476 479 Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 386 383 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 124 108 Midway Pipeline LLC Crude Oil Pipeline 50% 76 78 Red Oak Pipeline LLC (“Red Oak”) Crude Oil Pipeline (3) 50% 3 — Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 227 215 Settoon Towing, LLC Barge Transportation Services 50% 58 58 STACK Pipeline LLC Crude Oil Pipeline 50% 116 120 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 196 190 Wink to Webster Pipeline LLC (“W2W Pipeline”) Crude Oil Pipeline (3) 16% 79 — Total investments in unconsolidated entities $ 3,485 $ 2,702 (1) Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment. (2) The Capline pipeline was taken out of service in the fourth quarter of 2018. During the third quarter of 2019, the owners of Capline Pipeline Company LLC sanctioned the reversal of the Capline pipeline system. (3) Asset is currently under construction and has not yet been placed in service. |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consisted of the following (in millions): September 30, December 31, SHORT-TERM DEBT PAA senior notes: 2.60% senior notes due December 2019 $ 500 $ — 5.75% senior notes due January 2020 500 — Other 84 66 Total short-term debt 1,084 66 LONG-TERM DEBT PAA senior notes, net of unamortized discounts and debt issuance costs of $63 and $59, respectively (1) 8,937 8,941 PAA GO Zone term loans, net of debt issuance costs of $1 and $2, respectively, bearing a weighted-average interest rate of 2.9% and 3.1%, respectively 199 198 Other 37 4 Total long-term debt 9,173 9,143 Total debt (2) $ 10,257 $ 9,209 (1) As of December 31, 2018 , we classified PAA’s $500 million , 2.60% senior notes due December 2019 as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis. (2) PAA’s fixed-rate senior notes had a face value of approximately $10.0 billion and $9.0 billion at September 30, 2019 and December 31, 2018 , respectively. We estimated the aggregate fair value of these notes as of September 30, 2019 and December 31, 2018 to be approximately $10.3 billion and $8.6 billion , respectively. PAA’s 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 PAA’s credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy. |
Partners' Capital and Distrib_2
Partners' Capital and Distributions (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Partners' Capital and Distributions | |
Schedule of activity for Class A shares, Class B shares and Class C shares | The following tables present the activity for our Class A shares, Class B shares and Class C shares: Class A Shares Class B Shares Class C Shares Outstanding at December 31, 2018 159,485,588 119,604,338 516,938,280 Redemption Right exercises (1) — (91,672 ) 91,672 Other — — 226,814 Outstanding at March 31, 2019 159,485,588 119,512,666 517,256,766 Exchange Right exercises (1) 7,331,745 (7,331,745 ) — Redemption Right exercises (1) — (12,193,771 ) 12,193,771 Other — — 603,456 Outstanding at June 30, 2019 166,817,333 99,987,150 530,053,993 Exchange Right exercises (1) 15,173,490 (15,173,490 ) — Redemption Right exercises (1) — (16,254,598 ) 16,254,598 Other 15,186 — 588,771 Outstanding at September 30, 2019 182,006,009 68,559,062 546,897,362 Class A Shares Class B Shares Class C Shares Outstanding at December 31, 2017 156,111,139 126,984,572 510,925,432 Exchange Right exercises (1) 907,899 (907,899 ) — Redemption Right exercises (1) (39,224 ) 39,224 Issuance of Series A preferred units by a subsidiary — — 1,393,926 Other — — 17,766 Outstanding at March 31, 2018 157,019,038 126,037,449 512,376,348 Exchange Right exercises (1) 935,092 (935,092 ) — Redemption Right exercises (1) — (3,084,027 ) 3,084,027 Outstanding at June 30, 2018 157,954,130 122,018,330 515,460,375 Exchange Right exercises (1) 1,195,405 (1,195,405 ) — Redemption Right exercises (1) — (183,225 ) 183,225 Other 11,250 — 494,400 Outstanding at September 30, 2018 159,160,785 120,639,700 516,138,000 (1) See Note 12 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for information regarding Exchange Rights and Redemption Rights. |
AAP | |
Partners' Capital and Distributions | |
Schedule of distributions | The following table details the distributions to AAP’s partners paid during or pertaining to the first nine months of 2019 from distributions received from PAA (in millions): Distribution to AAP ’ s Partners Distribution Payment Date Noncontrolling Interests PAGP Total Cash Distributions November 14, 2019 (1) $ 25 $ 66 $ 91 August 14, 2019 $ 36 $ 60 $ 96 May 15, 2019 $ 44 $ 57 $ 101 February 14, 2019 $ 36 $ 48 $ 84 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . |
Class A Shares | |
Partners' Capital and Distributions | |
Schedule of distributions | The following table details distributions to our Class A shareholders paid during or pertaining to the first nine months of 2019 (in millions, except per share data): Distribution Payment Date Distributions to Class A Shareholders Distributions per Class A Share November 14, 2019 (1) $ 66 $ 0.36 August 14, 2019 $ 60 $ 0.36 May 15, 2019 $ 57 $ 0.36 February 14, 2019 $ 48 $ 0.30 (1) Payable to shareholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . |
Series A Preferred Units | PAA | |
Partners' Capital and Distributions | |
Schedule of distributions | The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first nine months of 2019 (in millions, except per unit data): Series A Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 14, 2019 (1) $ 37 $ 0.525 August 14, 2019 $ 37 $ 0.525 May 15, 2019 $ 37 $ 0.525 February 14, 2019 $ 37 $ 0.525 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . At September 30, 2019 , such amount was accrued to distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet. |
Series B Preferred Units | PAA | |
Partners' Capital and Distributions | |
Schedule of distributions | The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders during the first nine months of 2019 (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 15, 2019 (1) $ 24.5 $ 30.625 May 15, 2019 $ 24.5 $ 30.625 (1) Payable to unitholders of record at the close of business on November 1, 2019 for the period from May 15, 2019 through November 14, 2019. |
Common Units | PAA | |
Partners' Capital and Distributions | |
Schedule of distributions | The following table details distributions to PAA’s common unitholders paid during or pertaining to the first nine months of 2019 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP November 14, 2019 (1) $ 171 $ 91 $ 262 $ 0.36 August 14, 2019 $ 166 $ 96 $ 262 $ 0.36 May 15, 2019 $ 161 $ 101 $ 262 $ 0.36 February 14, 2019 $ 134 $ 84 $ 218 $ 0.30 (1) Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019 . |
Derivatives and Risk Manageme_2
Derivatives and Risk Management Activities (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Derivatives and Risk Management Activities | |
Impact of derivatives recognized in earnings | A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Three Months Ended September 30, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 149 $ (1 ) $ — $ — $ 148 Field operating costs (1) 4 — — — 4 Interest expense, net (2) — — — (2 ) (2 ) Other income/(expense), net (1) — — 1 — 1 Total gain/(loss) on derivatives recognized in net income $ 153 $ (1 ) $ 1 $ (2 ) $ 151 Three Months Ended September 30, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (59 ) $ 5 $ — $ — $ (54 ) Field operating costs (1) (1 ) — — — (1 ) Interest expense, net (2) — — — (2 ) (2 ) Other income/(expense), net (1) — — (2 ) — (2 ) Total gain/(loss) on derivatives recognized in net income $ (60 ) $ 5 $ (2 ) $ (2 ) $ (59 ) Nine Months Ended September 30, 2019 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ 380 $ 6 $ — $ — $ 386 Field operating costs (1) 15 — — — 15 Interest expense, net (2) — — — (7 ) (7 ) Other income/(expense), net (1) — — 16 — 16 Total gain/(loss) on derivatives recognized in net income $ 395 $ 6 $ 16 $ (7 ) $ 410 Nine Months Ended September 30, 2018 Location of Gain/(Loss) Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total Supply and Logistics segment revenues (1) $ (443 ) $ (7 ) $ — $ — $ (450 ) Field operating costs (1) — — — — — Interest expense, net (2) — — — (3 ) (3 ) Other income/(expense), net (1) — — 3 — 3 Total gain/(loss) on derivatives recognized in net income $ (443 ) $ (7 ) $ 3 $ (3 ) $ (450 ) (1) Derivatives not designated as a hedge. (2) Derivatives in hedging relationships. |
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 September 30, 2019 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 376 $ — $ — $ 376 $ — $ 376 Other long-term assets, net 59 — — 59 — 59 Other current liabilities 2 — — 2 — 2 Total Derivative Assets $ 437 $ — $ — $ 437 $ — $ 437 Derivative Liabilities Other current assets $ (67 ) $ — $ — $ (67 ) $ — $ (67 ) Other long-term assets, net (5 ) — — (5 ) — (5 ) Other current liabilities (14 ) (1 ) — (15 ) (64 ) (79 ) Other long-term liabilities and deferred credits (14 ) — (19 ) (33 ) — (33 ) Total Derivative Liabilities $ (100 ) $ (1 ) $ (19 ) $ (120 ) $ (64 ) $ (184 ) (1) Derivatives in hedging relationships. The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2018 (in millions): Derivatives Not Designated As Hedging Instruments Balance Sheet Location Commodity Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total Interest Rate Derivatives (1) Total Derivatives Derivative Assets Other current assets $ 441 $ — $ — $ 441 $ 2 $ 443 Other long-term assets, net 34 — — 34 — 34 Other long-term liabilities and deferred credits 3 — — 3 — 3 Total Derivative Assets $ 478 $ — $ — $ 478 $ 2 $ 480 Derivative Liabilities Other current assets $ (182 ) $ — $ — $ (182 ) $ — $ (182 ) Other long-term assets, net (7 ) — — (7 ) — (7 ) Other current liabilities (10 ) (9 ) — (19 ) (1 ) (20 ) Other long-term liabilities and deferred credits (9 ) — (36 ) (45 ) (8 ) (53 ) Total Derivative Liabilities $ (208 ) $ (9 ) $ (36 ) $ (253 ) $ (9 ) $ (262 ) (1) Derivatives in hedging relationships. |
Schedule of net broker receivable/(payable) | The following table provides the components of our net broker receivable/(payable): September 30, December 31, Initial margin $ 96 $ 95 Variation margin returned (131 ) (91 ) Letters of credit (75 ) (84 ) Net broker payable $ (110 ) $ (80 ) |
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): September 30, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 437 $ (184 ) $ 480 $ (262 ) Netting adjustment (74 ) 74 (192 ) 192 Cash collateral received (110 ) — (80 ) — Net position - asset/(liability) $ 253 $ (110 ) $ 208 $ (70 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 199 $ — $ 181 $ — Other long-term assets, net 54 — 27 — Other current liabilities — (77 ) — (20 ) Other long-term liabilities and deferred credits — (33 ) — (50 ) $ 253 $ (110 ) $ 208 $ (70 ) |
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): September 30, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 437 $ (184 ) $ 480 $ (262 ) Netting adjustment (74 ) 74 (192 ) 192 Cash collateral received (110 ) — (80 ) — Net position - asset/(liability) $ 253 $ (110 ) $ 208 $ (70 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 199 $ — $ 181 $ — Other long-term assets, net 54 — 27 — Other current liabilities — (77 ) — (20 ) Other long-term liabilities and deferred credits — (33 ) — (50 ) $ 253 $ (110 ) $ 208 $ (70 ) |
Net unrealized gain/(loss) recognized in AOCI for derivatives | The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Interest rate derivatives, net $ (53 ) $ 15 $ (111 ) $ 60 |
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 September 30, 2019 Fair Value as of December 31, 2018 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ 167 $ 190 $ (20 ) $ 337 $ 171 $ 87 $ 12 $ 270 Interest rate derivatives — (64 ) — (64 ) — (7 ) — (7 ) Foreign currency derivatives — (1 ) — (1 ) — (9 ) — (9 ) Preferred Distribution Rate Reset Option — — (19 ) (19 ) — — (36 ) (36 ) Total net derivative asset/(liability) $ 167 $ 125 $ (39 ) $ 253 $ 171 $ 71 $ (24 ) $ 218 (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 Nine Months Ended 2019 2018 2019 2018 Beginning Balance $ (26 ) $ (18 ) $ (24 ) $ (30 ) Net gains/(losses) for the period included in earnings 4 (5 ) 21 2 Settlements 1 — (10 ) 7 Derivatives entered into during the period (18 ) — (26 ) (2 ) Ending Balance $ (39 ) $ (23 ) $ (39 ) $ (23 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (14 ) $ (5 ) $ (5 ) $ — |
Commodity Derivatives | |
Derivatives and Risk Management Activities | |
Summary of open derivative positions | The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of September 30, 2019 : Notional Volume (Short)/Long Remaining Tenor Natural gas purchases 59.5 Bcf December 2022 Propane sales (5.7) MMbls March 2021 Butane sales (2.7) MMbls March 2021 Condensate sales (WTI position) (0.7) MMbls March 2021 Specification products sales (put option) 0.1 MMbls March 2020 Power supply requirements (1) 1.0 TWh December 2022 (1) Power position to hedge a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants. |
Interest Rate Derivatives | |
Derivatives and Risk Management Activities | |
Schedule of terms of outstanding interest rate derivatives | The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2019 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting Anticipated interest payments 8 forward starting swaps $ 200 6/15/2020 3.06 % Cash flow hedge |
Foreign Currency Derivatives | |
Derivatives and Risk Management Activities | |
Summary of open derivative positions | The following table summarizes our open forward exchange contracts as of September 30, 2019 (in millions): USD CAD Average Exchange Rate Forward exchange contracts that exchange CAD for USD: 2019 $ 42 $ 56 $1.00 - $1.32 Forward exchange contracts that exchange USD for CAD: 2019 $ 98 $ 130 $1.00 - $1.32 |
Leases (Tables)
Leases (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Schedule of lease costs and other lessee information | The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions): Lease Cost Three Months Ended Nine Months Ended Operating lease cost $ 32 $ 95 Short-term lease cost 11 32 Other (1) (1 ) — Total lease cost $ 42 $ 127 (1) Includes immaterial finance lease costs, variable lease costs and sublease income. The following table presents information related to cash flows arising from lease transactions (in millions): Nine Months Ended Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 101 Financing cash flows for finance leases $ 13 Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications: Operating leases $ 16 Finance leases $ 10 Information related to the weighted-average remaining lease term and discount rate is presented in the table below: September 30, 2019 Weighted-average remaining lease term (in years): Operating leases 10.2 Finance leases 3.6 Weighted-average discount rate: Operating leases 4.5% Finance leases 2.4% |
Lease Assets and Liabilities | The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Condensed Consolidated Balance Sheet (in millions): Leases Balance Sheet Location September 30, 2019 Assets Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 443 Finance lease right-of-use assets Property and equipment $ 110 Accumulated depreciation (15 ) Property and equipment, net $ 95 Total lease right-of-use assets $ 538 Liabilities Operating lease liabilities Current Other current liabilities $ 103 Noncurrent Long-term operating lease liabilities 348 Total operating lease liabilities $ 451 Finance lease liabilities Current Short-term debt $ 19 Noncurrent Other long-term debt, net 37 Total finance lease liabilities $ 56 Total lease liabilities $ 507 |
Schedule of Operating Lease Maturity | The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of September 30, 2019 reconciled to our lease liabilities on our Condensed Consolidated Balance Sheet (amounts in millions): Operating Finance Future minimum lease payments (1) : Remainder of 2019 $ 31 $ 5 2020 113 18 2021 93 9 2022 78 10 2023 54 7 Thereafter 247 10 Total 616 59 Less: Present value discount (165 ) (3 ) Lease liabilities $ 451 $ 56 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet. |
Schedule of Finance Lease Maturity | The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of September 30, 2019 reconciled to our lease liabilities on our Condensed Consolidated Balance Sheet (amounts in millions): Operating Finance Future minimum lease payments (1) : Remainder of 2019 $ 31 $ 5 2020 113 18 2021 93 9 2022 78 10 2023 54 7 Thereafter 247 10 Total 616 59 Less: Present value discount (165 ) (3 ) Lease liabilities $ 451 $ 56 (1) Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet. |
Schedule of Lessor Future Revenues Maturity | The table below presents the maturity of lease payments for operating lease agreements in effect as of September 30, 2019 . This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 23 years . The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions): Remainder 2020 2021 2022 2023 Thereafter Lease revenue $ 5 $ 19 $ 22 $ 25 $ 21 $ 226 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions | The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Revenues from related parties (1) (2) $ 205 $ 266 $ 661 $ 832 Purchases and related costs from related parties (2) $ (7 ) $ 157 $ 93 $ 317 (1) A majority of these revenues are included in “Supply and Logistics segment revenues” on our Condensed Consolidated Statements of Operations. (2) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations. Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions): September 30, December 31, Trade accounts receivable and other receivables, net from related parties (1) (2) $ 165 $ 144 Trade accounts payable to related parties (1) (2) (3) $ 105 $ 121 (1) We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts. (2) Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager. (3) We have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities. |
Operating Segments (Tables)
Operating Segments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Segment Reporting [Abstract] | |
Segment financial data | The following tables reflect certain financial data for each segment (in millions): Three Months Ended September 30, 2019 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 319 $ 149 $ 7,541 $ (123 ) $ 7,886 Intersegment (2) 278 142 1 123 544 Total revenues of reportable segments $ 597 $ 291 $ 7,542 $ — $ 8,430 Equity earnings in unconsolidated entities $ 102 $ — $ — $ 102 Segment Adjusted EBITDA $ 462 $ 173 $ 92 $ 727 Maintenance capital $ 42 $ 28 $ 15 $ 85 Three Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 292 $ 149 $ 8,482 $ (131 ) $ 8,792 Intersegment (2) 206 140 1 131 478 Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ — $ 9,270 Equity earnings in unconsolidated entities $ 110 $ — $ — $ 110 Segment Adjusted EBITDA $ 388 $ 173 $ 75 $ 636 Maintenance capital $ 41 $ 33 $ 4 $ 78 Nine Months Ended September 30, 2019 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 938 $ 457 $ 23,477 $ (357 ) $ 24,515 Intersegment (2) 774 423 3 357 1,557 Total revenues of reportable segments $ 1,712 $ 880 $ 23,480 $ — $ 26,072 Equity earnings in unconsolidated entities $ 274 $ — $ — $ 274 Segment Adjusted EBITDA $ 1,271 $ 529 $ 571 $ 2,371 Maintenance capital $ 110 $ 74 $ 20 $ 204 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 808 $ 437 $ 24,374 $ (350 ) $ 25,269 Intersegment (2) 619 429 2 350 1,400 Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ — $ 26,669 Equity earnings in unconsolidated entities $ 281 $ — $ — $ 281 Segment Adjusted EBITDA $ 1,083 $ 530 $ 120 $ 1,733 Maintenance capital $ 102 $ 74 $ 10 $ 186 (1) Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2018 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 revenues from External customers presented above and adjusted those revenues out such that Total revenues 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 activities are conducted at posted tariff rates where applicable, or otherwise at 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 PAGP | The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAGP (in millions): Three Months Ended Nine Months Ended 2019 2018 2019 2018 Segment Adjusted EBITDA $ 727 $ 636 $ 2,371 $ 1,733 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (18 ) (15 ) (45 ) (44 ) Gains/(losses) from derivative activities, net of inventory valuation adjustments (3) 29 110 60 (107 ) Long-term inventory costing adjustments (4) 1 10 (3 ) 18 Deficiencies under minimum volume commitments, net (5) 4 4 10 (9 ) Equity-indexed compensation expense (6) (5 ) (14 ) (13 ) (37 ) Net gain/(loss) on foreign currency revaluation (7) 5 3 (7 ) (5 ) Line 901 incident (8) — — (10 ) — Unallocated general and administrative expenses (1 ) (1 ) (4 ) (3 ) Depreciation and amortization (157 ) (129 ) (441 ) (386 ) Gains/(losses) on asset sales and asset impairments, net 7 (2 ) 7 79 Gain on investment in unconsolidated entities 4 210 271 210 Interest expense, net (108 ) (110 ) (311 ) (327 ) Other income/(expense), net 5 (3 ) 23 8 Income before tax 493 699 1,908 1,130 Income tax expense (62 ) (23 ) (137 ) (84 ) Net income 431 676 1,771 1,046 Net income attributable to noncontrolling interests (361 ) (565 ) (1,488 ) (892 ) Net income attributable to PAGP $ 70 $ 111 $ 283 $ 154 (1) Represents adjustments utilized by our CODM in the evaluation of segment results. (2) Includes our proportionate share of the depreciation and amortization of, and gains and losses on significant asset sales by, unconsolidated entities. (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 PAA common units. (7) Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. (8) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 13 for additional information regarding the Line 901 incident. |
Organization and Basis of Con_2
Organization and Basis of Consolidation and Presentation - Additional Information (Details) shares in Millions, $ in Millions | 9 Months Ended | |
Sep. 30, 2019USD ($)segmentshares | Dec. 31, 2018USD ($) | |
Organization and basis of presentation | ||
Operating segments number | segment | 3 | |
Deferred tax asset | $ | $ 1,301 | $ 1,304 |
PAA | AAP | ||
Organization and basis of presentation | ||
Ownership interest | 32.00% | |
Ownership interest | 252.2 | |
GP LLC | ||
Organization and basis of presentation | ||
Ownership interest | 100.00% | |
AAP | ||
Organization and basis of presentation | ||
Ownership interest | 73.00% | |
Ownership interest | 181 | |
AAP | GP LLC | ||
Organization and basis of presentation | ||
Ownership interest | 1 | |
Consolidated Entity Excluding VIE | ||
Organization and basis of presentation | ||
Deferred tax asset | $ | $ 1,301 | $ 1,304 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 611 | $ 69 | ||
Restricted cash | 59 | |||
Total cash and cash equivalents and restricted cash | $ 670 | $ 69 | $ 33 | $ 40 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Jan. 01, 2019 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Net lease right-of-use assets recognized upon adoption of Topic 842 | $ 538 | |
Lease liabilities recognized upon adoption of Topic 842 | $ 507 | |
ASU 2016-02 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Net lease right-of-use assets recognized upon adoption of Topic 842 | $ 560 | |
Lease liabilities recognized upon adoption of Topic 842 | $ 570 |
Revenues and Accounts Receiva_3
Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ 8,258 | $ 9,315 | $ 25,624 | $ 27,093 |
Supply and Logistics | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 7,387 | 8,534 | 23,096 | 24,832 |
Supply and Logistics | Crude oil transactions | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 7,185 | 7,978 | 21,716 | 22,651 |
Supply and Logistics | NGL and other transactions | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 202 | 556 | 1,380 | 2,181 |
Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 590 | 496 | 1,685 | 1,416 |
Transportation | Total tariff activities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 557 | 460 | 1,579 | 1,313 |
Transportation | Crude oil pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 532 | 435 | 1,504 | 1,237 |
Transportation | NGL pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 25 | 25 | 75 | 76 |
Transportation | Trucking | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 33 | 36 | 106 | 103 |
Facilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 281 | 285 | 843 | 845 |
Facilities | Crude oil, NGL and other terminalling and storage | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 174 | 174 | 523 | 511 |
Facilities | NGL and natural gas processing and fractionation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 87 | 87 | 262 | 278 |
Facilities | Rail load / unload | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ 20 | $ 24 | $ 58 | $ 56 |
Revenues and Accounts Receiva_4
Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||||
Total revenues | $ 7,886 | $ 8,792 | $ 24,515 | $ 25,269 |
Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 196 | 161 | 581 | 458 |
Facilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 149 | 149 | 457 | 437 |
Supply and Logistics | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 7,541 | 8,482 | 23,477 | 24,374 |
Operating Segments | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 8,258 | 9,315 | 25,624 | 27,093 |
Total revenues | 8,430 | 9,270 | 26,072 | 26,669 |
Operating Segments | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 590 | 496 | 1,685 | 1,416 |
Total revenues | 597 | 498 | 1,712 | 1,427 |
Operating Segments | Facilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 281 | 285 | 843 | 845 |
Total revenues | 291 | 289 | 880 | 866 |
Operating Segments | Supply and Logistics | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 7,387 | 8,534 | 23,096 | 24,832 |
Total revenues | 7,542 | 8,483 | 23,480 | 24,376 |
Intersegment | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (544) | (478) | (1,557) | (1,400) |
Intersegment | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (278) | (206) | (774) | (619) |
Intersegment | Facilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (142) | (140) | (423) | (429) |
Intersegment | Supply and Logistics | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (1) | (1) | (3) | (2) |
Other | Operating Segments | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 172 | (45) | 448 | (424) |
Other | Operating Segments | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 7 | 2 | 27 | 11 |
Other | Operating Segments | Facilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 10 | 4 | 37 | 21 |
Other | Operating Segments | Supply and Logistics | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | $ 155 | $ (51) | $ 384 | $ (456) |
Revenues and Accounts Receiva_5
Revenues and Accounts Receivable - Contract Balances (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Change in Contract with Customer, Liability [Roll Forward] | |
Beginning balance | $ 338 |
Amounts recognized as revenue | (226) |
Additions | 82 |
Other | (1) |
Ending balance | $ 193 |
Revenues and Accounts Receiva_6
Revenues and Accounts Receivable - Narrative (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Minimum Volume Commitments [Line Items] | ||
Contract liability | $ 193 | $ 338 |
Minimum Volume Commitments | ||
Minimum Volume Commitments [Line Items] | ||
Counterparty deficiencies | 50 | 62 |
Contract liability | 30 | 40 |
Counterparty deficiencies unbilled and uncollected | $ 20 | $ 22 |
Revenues and Accounts Receiva_7
Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions | Sep. 30, 2019USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 155 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 531 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 441 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 380 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 343 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 1,332 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 41 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 162 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 171 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 169 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 167 |
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 849 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 114 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 369 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 270 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 211 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | 176 |
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | |
Remaining performance obligation | $ 483 |
Revenues and Accounts Receiva_8
Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2019 | Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | ||
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 |
Trade accounts receivable arising from revenues from contracts with customers | 2,628 | 2,277 |
Other trade accounts receivables and other receivables | 3,076 | 2,732 |
Impact due to contractual rights of offset with counterparties | (2,792) | (2,555) |
Trade accounts receivable and other receivables, net | $ 2,912 | $ 2,454 |
Net Income Per Class A Share (D
Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Basic Net Income per Class A Share | ||||
Net income attributable to PAGP | $ 70 | $ 111 | $ 283 | $ 154 |
Diluted Net Income per Class A Share | ||||
Net income attributable to PAGP | 70 | 111 | 283 | 154 |
Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units | 1 | |||
Net income attributable to PAGP including incremental net income from assumed exchange of AAP Management Units | $ 70 | $ 111 | $ 284 | $ 154 |
Class A Shares | ||||
Basic Net Income per Class A Share | ||||
Basic weighted average Class A shares outstanding (in shares) | 168 | 158 | 163 | 157 |
Basic net income per Class A share (in dollars per share) | $ 0.41 | $ 0.70 | $ 1.73 | $ 0.98 |
Diluted Net Income per Class A Share | ||||
Basic weighted average Class A shares outstanding (in shares) | 168 | 158 | 163 | 157 |
Dilutive shares resulting from assumed exchange of AAP Management Units (in shares) | 2 | |||
Diluted weighted average Class A shares outstanding (in shares) | 168 | 158 | 165 | 157 |
Diluted net income per Class A share (in dollars per share) | $ 0.41 | $ 0.70 | $ 1.72 | $ 0.98 |
Maximum | ||||
Net Income Per Class A Share | ||||
Dilutive LTIP awards (shares), less than | 0.1 | 0.1 | 0.1 | 0.1 |
Inventory, Linefill and Base _3
Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions | Sep. 30, 2019USD ($)$ / Mcf$ / bblbblMcf | Dec. 31, 2018USD ($)$ / Mcf$ / bblbblMcf |
Inventory by category | ||
Inventory | $ 816 | $ 640 |
Linefill and base gas | 930 | 916 |
Long-term inventory | 159 | 136 |
Total | 1,905 | 1,692 |
Crude oil | ||
Inventory by category | ||
Inventory | 616 | 367 |
Linefill and base gas | 775 | 761 |
Long-term inventory | $ 138 | $ 79 |
Inventory, Volumes (in barrels or in Mcf) | bbl | 11,481 | 9,657 |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 13,513 | 13,312 |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 2,587 | 1,890 |
Inventory (Price/Unit of measure) | $ / bbl | 53.65 | 38 |
Linefill and base gas (Price/Unit of measure) | $ / bbl | 57.35 | 57.17 |
Long-term inventory (Price/Unit of measure) | $ / bbl | 53.34 | 41.80 |
NGL | ||
Inventory by category | ||
Inventory | $ 182 | $ 262 |
Linefill and base gas | 47 | 47 |
Long-term inventory | $ 21 | $ 57 |
Inventory, Volumes (in barrels or in Mcf) | bbl | 12,449 | 10,384 |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 1,715 | 1,730 |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 1,707 | 2,368 |
Inventory (Price/Unit of measure) | $ / bbl | 14.62 | 25.23 |
Linefill and base gas (Price/Unit of measure) | $ / bbl | 27.41 | 27.17 |
Long-term inventory (Price/Unit of measure) | $ / bbl | 12.30 | 24.07 |
Natural gas | ||
Inventory by category | ||
Linefill and base gas | $ 108 | $ 108 |
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf | 24,976 | 24,976 |
Linefill and base gas (Price/Unit of measure) | $ / Mcf | 4.32 | 4.32 |
Other | ||
Inventory by category | ||
Inventory | $ 18 | $ 11 |
Goodwill (Details)
Goodwill (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Changes in goodwill | |
Beginning Balance | $ 2,521 |
Foreign currency translation adjustments | 11 |
Ending Balance | 2,532 |
Goodwill impairment | 0 |
Operating Segments | Transportation | |
Changes in goodwill | |
Beginning Balance | 1,040 |
Foreign currency translation adjustments | 7 |
Ending Balance | 1,047 |
Operating Segments | Facilities | |
Changes in goodwill | |
Beginning Balance | 978 |
Foreign currency translation adjustments | 2 |
Ending Balance | 980 |
Operating Segments | Supply and Logistics | |
Changes in goodwill | |
Beginning Balance | 503 |
Foreign currency translation adjustments | 2 |
Ending Balance | $ 505 |
Investments in Unconsolidated_3
Investments in Unconsolidated Entities Investments in Unconsolidated Entities (Details) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Mar. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2021USD ($)bbl | Jun. 30, 2019 | Dec. 31, 2018USD ($) | |
Investments in Unconsolidated Entities | |||||
Investments in unconsolidated entities | $ 3,485 | $ 2,702 | |||
Carrying value of undivided joint interest | $ 15,269 | 14,802 | |||
Advantage Pipeline Holdings LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 74 | 72 | |||
BridgeTex Pipeline Company, LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 20.00% | ||||
Investments in unconsolidated entities | $ 432 | 435 | |||
Cactus II Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 65.00% | ||||
Investments in unconsolidated entities | $ 666 | 455 | |||
Caddo Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 66 | 65 | |||
Capline Pipeline Company LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 54.00% | ||||
Investments in unconsolidated entities | $ 462 | ||||
Fair value of investment in unconsolidated entity | $ 444 | ||||
Cheyenne Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 44 | 44 | |||
Diamond Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 476 | 479 | |||
Eagle Ford Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 386 | 383 | |||
Eagle Ford Terminals Corpus Christi LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 124 | 108 | |||
Midway Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 76 | 78 | |||
Red Oak Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 3 | ||||
Saddlehorn Pipeline Company, LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 40.00% | ||||
Investments in unconsolidated entities | $ 227 | 215 | |||
Settoon Towing, LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 58 | 58 | |||
STACK Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 50.00% | ||||
Investments in unconsolidated entities | $ 116 | 120 | |||
White Cliffs Pipeline, LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 36.00% | ||||
Investments in unconsolidated entities | $ 196 | $ 190 | |||
Wink to Webster Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Ownership interest in unconsolidated entity | 16.00% | 20.00% | |||
Investments in unconsolidated entities | $ 79 | ||||
Undivided joint interest in Capline pipeline system | |||||
Investments in Unconsolidated Entities | |||||
Undivided joint interest ownership percentage | 54.00% | ||||
Carrying value of undivided joint interest | $ 175 | ||||
Midland, Texas To Webster, Texas pipeline segment | Third Party | Undivided joint interest in pipeline segment | |||||
Investments in Unconsolidated Entities | |||||
Undivided joint interest ownership percentage | 29.00% | ||||
Midland, Texas To Webster, Texas pipeline segment | Wink to Webster Pipeline LLC | Undivided joint interest in pipeline segment | |||||
Investments in Unconsolidated Entities | |||||
Undivided joint interest ownership percentage | 71.00% | ||||
Capline pipeline system | Capline Pipeline Company LLC | |||||
Investments in Unconsolidated Entities | |||||
Percentage of Capline pipeline system owned | 100.00% | ||||
Gain on investment in unconsolidated entities | Capline Pipeline Company LLC | |||||
Investments in Unconsolidated Entities | |||||
Gain from remeasurement to fair value of retained investment | $ 269 | ||||
Forecast | Red Oak Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Future increase in investment from contribution | $ 155 | ||||
Forecast | Sunrise II Pipeline | Red Oak Pipeline LLC | |||||
Investments in Unconsolidated Entities | |||||
Pipeline capacity to be contributed (bbls) | bbl | 260,000 | ||||
Term of contract | 33 years |
Debt - Components (Details)
Debt - Components (Details) - USD ($) $ in Millions | Nov. 15, 2019 | Sep. 30, 2019 | Dec. 31, 2018 |
Short-term debt: | |||
Total short-term debt | $ 1,084 | $ 66 | |
Long-term debt: | |||
PAA senior notes, net of unamortized discounts and debt issuance costs of $63 and $59, respectively | 8,937 | 8,941 | |
Other long-term debt, net | 236 | 202 | |
Total long-term debt | 9,173 | 9,143 | |
Total debt | 10,257 | 9,209 | |
Senior notes | |||
Long-term debt: | |||
PAA senior notes, net of unamortized discounts and debt issuance costs of $63 and $59, respectively | 8,937 | 8,941 | |
Unamortized discounts and debt issuance costs | 63 | 59 | |
Debt instrument face value | 10,000 | 9,000 | |
Other | |||
Long-term debt: | |||
Other long-term debt, net | 37 | 4 | |
Level 2 | Senior notes | |||
Long-term debt: | |||
Debt instrument fair value | 10,300 | 8,600 | |
Other | |||
Short-term debt: | |||
Total short-term debt | 84 | $ 66 | |
2.60% senior notes due December 2019 | Senior notes | |||
Short-term debt: | |||
Stated percentage | 2.60% | ||
Long-term debt: | |||
Debt instrument face value | $ 500 | ||
2.60% senior notes due December 2019 | Senior notes | |||
Short-term debt: | |||
Short-term debt | $ 500 | ||
Stated percentage | 2.60% | ||
5.75% senior notes due January 2020 | Senior notes | |||
Short-term debt: | |||
Short-term debt | $ 500 | ||
Stated percentage | 5.75% | ||
GO Zone term loans | Term loan | |||
Long-term debt: | |||
Other long-term debt, net | $ 199 | $ 198 | |
Weighted average interest rate, long-term | 2.90% | 3.10% | |
Debt issuance costs | $ 1 | $ 2 | |
Forecast | 2.60% senior notes due December 2019 | Senior notes | |||
Short-term debt: | |||
Senior notes to be redeemed | $ 500 |
Debt - Letters of Credit, Borr
Debt - Letters of Credit, Borrowings and Repayments (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Debt | |||
Outstanding letters of credit | $ 149 | $ 184 | |
Credit facilities and PAA commercial paper program | |||
Debt | |||
Total borrowings | 10,500 | $ 38,600 | |
Total repayments | 10,500 | $ 39,200 | |
Senior notes | |||
Debt | |||
Debt instrument face value | 10,000 | $ 9,000 | |
Senior notes | 3.55% Senior Notes Due December 2029 | |||
Debt | |||
Debt instrument face value | $ 1,000 | ||
Stated percentage | 3.55% | ||
Offering price | Senior notes | 3.55% Senior Notes Due December 2029 | |||
Debt | |||
Measurement input | 0.99801 |
Partners' Capital and Distrib_3
Partners' Capital and Distributions - Exchange Rights and Shares Activity (Details) - shares | 3 Months Ended | |||||
Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | |
Class A Shares | ||||||
Activity for Class A shares, Class B shares and Class C shares | ||||||
Balance, beginning of period (shares) | 166,817,333 | 159,485,588 | 159,485,588 | 157,954,130 | 157,019,038 | 156,111,139 |
Exchange Right exercises (shares) | 15,173,490 | 7,331,745 | 1,195,405 | 935,092 | 907,899 | |
Other (shares) | 15,186 | 11,250 | ||||
Balance, end of period (shares) | 182,006,009 | 166,817,333 | 159,485,588 | 159,160,785 | 157,954,130 | 157,019,038 |
Class B Shares | ||||||
Activity for Class A shares, Class B shares and Class C shares | ||||||
Balance, beginning of period (shares) | 99,987,150 | 119,512,666 | 119,604,338 | 122,018,330 | 126,037,449 | 126,984,572 |
Exchange Right exercises (shares) | (15,173,490) | (7,331,745) | (1,195,405) | (935,092) | (907,899) | |
Redemption Right exercises (shares) | (16,254,598) | (12,193,771) | (91,672) | (183,225) | (3,084,027) | (39,224) |
Balance, end of period (shares) | 68,559,062 | 99,987,150 | 119,512,666 | 120,639,700 | 122,018,330 | 126,037,449 |
Class C Shares | ||||||
Activity for Class A shares, Class B shares and Class C shares | ||||||
Balance, beginning of period (shares) | 530,053,993 | 517,256,766 | 516,938,280 | 515,460,375 | 512,376,348 | 510,925,432 |
Redemption Right exercises (shares) | 16,254,598 | 12,193,771 | 91,672 | 183,225 | 3,084,027 | 39,224 |
Issuance of Series A preferred units by a subsidiary (shares) | 1,393,926 | |||||
Other (shares) | 588,771 | 603,456 | 226,814 | 494,400 | 17,766 | |
Balance, end of period (shares) | 546,897,362 | 530,053,993 | 517,256,766 | 516,138,000 | 515,460,375 | 512,376,348 |
Partners' Capital and Distrib_4
Partners' Capital and Distributions - Distributions, Class A (Details) - Cash Distribution - Class A Shares - USD ($) $ / shares in Units, $ in Millions | Nov. 14, 2019 | Aug. 14, 2019 | May 15, 2019 | Feb. 14, 2019 |
Partners' Capital and Distributions | ||||
Distributions to Class A shareholders | $ 60 | $ 57 | $ 48 | |
Distribution per Class A share, paid (usd per share) | $ 0.36 | $ 0.36 | $ 0.30 | |
Forecast | ||||
Partners' Capital and Distributions | ||||
Distributions to Class A shareholders | $ 66 | |||
Distribution per Class A share, paid (usd per share) | $ 0.36 |
Partners' Capital and Distrib_5
Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended |
May 31, 2019 | Sep. 30, 2019 | |
Partners' Capital and Distributions | ||
Amount received for sale of noncontrolling interest in a subsidiary | $ 128 | |
AAP | ||
Partners' Capital and Distributions | ||
Noncontrolling interests in subsidiaries (percent) | 27.00% | |
Red River LLC | ||
Partners' Capital and Distributions | ||
Noncontrolling interests in subsidiaries (percent) | 33.00% | |
Red River LLC | Delek | ||
Partners' Capital and Distributions | ||
Amount received for sale of noncontrolling interest in a subsidiary | $ 128 | |
Common Units and Series A Preferred Units | PAA | ||
Partners' Capital and Distributions | ||
Noncontrolling interests in subsidiaries (percent) | 68.00% | |
Series B Preferred Units | PAA | ||
Partners' Capital and Distributions | ||
Noncontrolling interests in subsidiaries (percent) | 100.00% | |
Delek | Red River LLC | ||
Partners' Capital and Distributions | ||
Noncontrolling interests in subsidiaries (percent) | 33.00% | 33.00% |
Cash Distribution | Red River LLC | ||
Partners' Capital and Distributions | ||
Distributions to noncontrolling interests | $ 4 |
Partners' Capital and Distrib_6
Partners' Capital and Distributions - Subsidiary Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 15, 2019 | Nov. 14, 2019 | Aug. 14, 2019 | May 15, 2019 | Feb. 14, 2019 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 |
Partners' Capital and Distributions | |||||||||
Total distributions paid | $ 315 | $ 267 | $ 894 | $ 802 | |||||
PAA | Series A Preferred Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Preferred unit distribution amount | $ 37 | $ 37 | $ 37 | ||||||
Preferred unit distribution amount (in dollars per unit) | $ 0.525 | $ 0.525 | $ 0.525 | ||||||
PAA | Series B Preferred Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Preferred unit distribution amount | $ 24.5 | ||||||||
Preferred unit distribution amount (in dollars per unit) | $ 30.625 | ||||||||
PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Total distributions paid | $ 262 | $ 262 | $ 218 | ||||||
Distributions per common unit, paid (usd per unit) | $ 0.36 | $ 0.36 | $ 0.30 | ||||||
AAP | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to noncontrolling interests | $ 36 | $ 44 | $ 36 | ||||||
Distributions to PAGP | 60 | 57 | 48 | ||||||
Total distributions paid | 96 | 101 | 84 | ||||||
Forecast | PAA | Series A Preferred Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Preferred unit distribution amount | $ 37 | ||||||||
Preferred unit distribution amount (in dollars per unit) | $ 0.525 | ||||||||
Forecast | PAA | Series B Preferred Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Preferred unit distribution amount | $ 24.5 | ||||||||
Preferred unit distribution amount (in dollars per unit) | $ 30.625 | ||||||||
Forecast | PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Total distributions paid | $ 262 | ||||||||
Distributions per common unit, paid (usd per unit) | $ 0.36 | ||||||||
Forecast | AAP | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to noncontrolling interests | $ 25 | ||||||||
Distributions to PAGP | 66 | ||||||||
Total distributions paid | 91 | ||||||||
Public | PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to common unitholders | 166 | 161 | 134 | ||||||
Public | Forecast | PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to common unitholders | 171 | ||||||||
AAP | PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to common unitholders | $ 96 | $ 101 | $ 84 | ||||||
AAP | Forecast | PAA | Common Units | Cash Distribution | |||||||||
Partners' Capital and Distributions | |||||||||
Distributions to common unitholders | $ 91 | ||||||||
Other current liabilities | PAA | Series B Preferred Units | |||||||||
Partners' Capital and Distributions | |||||||||
Amount accrued to distributions payable | $ 18 | $ 18 |
Derivatives and Risk Manageme_3
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions | 9 Months Ended |
Sep. 30, 2019TWhbblBcfMMBbls | |
Net long position associated with crude oil purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | 3.1 |
Net short time spread position hedging anticipated crude oil lease gathering purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | 6.9 |
Net crude oil basis spread position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | 23.1 |
Net short position related to anticipated net sales of crude oil and NGL inventory | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | 12.1 |
Positions hedging risk storage capacity will not be utilized | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | 0.9 |
Long natural gas position for natural gas purchases and operational needs | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | Bcf | 59.5 |
Short propane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls | 5.7 |
Short butane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls | 2.7 |
Short condensate WTI position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls | 0.7 |
Net long position contracts related to anticipated sales of specification products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls | 0.1 |
Long power position for power supply requirements | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in Terawatt hours) | TWh | 1 |
Derivatives and Risk Manageme_4
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - 8 forward starting interest rate swaps (30-year), 3.06% - Cash flow hedge $ in Millions | 9 Months Ended |
Sep. 30, 2019USD ($)contract | |
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) | 3.06% |
Derivatives and Risk Manageme_5
Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) $ in Millions, $ in Millions | Sep. 30, 2019USD ($)$ / $ | Sep. 30, 2019CAD ($)$ / $ |
Forward exchange contracts that exchange CAD For USD maturing in 2019 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | $ 42 | $ 56 |
Average exchange rate (cad per usd) | 1.32 | 1.32 |
Forward exchange contracts that exchange USD for CAD maturing in 2019 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | $ 98 | $ 130 |
Average exchange rate (cad per usd) | 1.32 | 1.32 |
Derivatives and Risk Manageme_6
Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | $ 151 | $ (59) | $ 410 | $ (450) |
Supply and Logistics segment revenues | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | 148 | (54) | 386 | (450) |
Field operating costs | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | 4 | (1) | 15 | |
Interest expense, net | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | (2) | (2) | (7) | (3) |
Other income/(expense), net | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | 1 | (2) | 16 | 3 |
Commodity Derivatives | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | 153 | (60) | 395 | (443) |
Foreign Currency Derivatives | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | (1) | 5 | 6 | (7) |
Preferred Distribution Rate Reset Option | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | 1 | (2) | 16 | 3 |
Interest Rate Derivatives | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | (2) | (2) | (7) | (3) |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense, net | ||||
Impact of derivative activities recognized in earnings | ||||
Total gain/(loss) on derivatives recognized in net income | (2) | (2) | (7) | (3) |
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 | 149 | (59) | 380 | (443) |
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 | 4 | (1) | 15 | |
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 | (1) | 5 | 6 | (7) |
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 | $ 1 | $ (2) | $ 16 | $ 3 |
Derivatives and Risk Manageme_7
Derivatives and Risk Management Activities - Assets and Liabilities (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | $ 437 | $ 437 | $ 480 | ||
Liability Derivatives Fair Value | (184) | (184) | (262) | ||
Net loss expected to be reclassified to earnings in the next twelve months | 10 | ||||
Other current assets | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 376 | 376 | 443 | ||
Liability Derivatives Fair Value | (67) | (67) | (182) | ||
Other long-term assets, net | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 59 | 59 | 34 | ||
Liability Derivatives Fair Value | (5) | (5) | (7) | ||
Other current liabilities | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 2 | 2 | |||
Liability Derivatives Fair Value | (79) | (79) | (20) | ||
Other long-term liabilities and deferred credits | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 3 | ||||
Liability Derivatives Fair Value | (33) | (33) | (53) | ||
Interest Rate Derivatives | |||||
Derivative assets and liabilities | |||||
Net unrealized gain/(loss) recognized in AOCI | (53) | $ 15 | (111) | $ 60 | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 2 | ||||
Liability Derivatives Fair Value | (64) | (64) | (9) | ||
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current assets | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 2 | ||||
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities | |||||
Derivative assets and liabilities | |||||
Liability Derivatives Fair Value | (64) | (64) | (1) | ||
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits | |||||
Derivative assets and liabilities | |||||
Liability Derivatives Fair Value | (8) | ||||
Derivatives Not Designated as a Hedge | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 437 | 437 | 478 | ||
Liability Derivatives Fair Value | (120) | (120) | (253) | ||
Derivatives Not Designated as a Hedge | Other current assets | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 376 | 376 | 441 | ||
Liability Derivatives Fair Value | (67) | (67) | (182) | ||
Derivatives Not Designated as a Hedge | Other long-term assets, net | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 59 | 59 | 34 | ||
Liability Derivatives Fair Value | (5) | (5) | (7) | ||
Derivatives Not Designated as a Hedge | Other current liabilities | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 2 | 2 | |||
Liability Derivatives Fair Value | (15) | (15) | (19) | ||
Derivatives Not Designated as a Hedge | Other long-term liabilities and deferred credits | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 3 | ||||
Liability Derivatives Fair Value | (33) | (33) | (45) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 437 | 437 | 478 | ||
Liability Derivatives Fair Value | (100) | (100) | (208) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 376 | 376 | 441 | ||
Liability Derivatives Fair Value | (67) | (67) | (182) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 59 | 59 | 34 | ||
Liability Derivatives Fair Value | (5) | (5) | (7) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 2 | 2 | |||
Liability Derivatives Fair Value | (14) | (14) | (10) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits | |||||
Derivative assets and liabilities | |||||
Asset Derivatives Fair Value | 3 | ||||
Liability Derivatives Fair Value | (14) | (14) | (9) | ||
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | |||||
Derivative assets and liabilities | |||||
Liability Derivatives Fair Value | (1) | (1) | (9) | ||
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities | |||||
Derivative assets and liabilities | |||||
Liability Derivatives Fair Value | (1) | (1) | (9) | ||
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | |||||
Derivative assets and liabilities | |||||
Liability Derivatives Fair Value | (19) | (19) | (36) | ||
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 | (19) | (19) | $ (36) | ||
AOCI cash flow hedge | |||||
Derivative assets and liabilities | |||||
Net loss deferred in AOCI | $ 281 | $ 281 |
Derivatives and Risk Manageme_8
Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Offsetting Assets, Liabilities [Line Items] | ||
Initial margin | $ 96 | $ 95 |
Variation margin returned | (131) | (91) |
Letters of credit | (149) | (184) |
Net broker payable | (110) | (80) |
Exchange Traded | ||
Offsetting Assets, Liabilities [Line Items] | ||
Letters of credit | $ (75) | $ (84) |
Derivatives and Risk Manageme_9
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Derivative Asset Positions | ||
Gross Position - Asset | $ 437 | $ 480 |
Netting adjustment | (74) | (192) |
Cash collateral received | (110) | (80) |
Net Position - Asset | 253 | 208 |
Derivative Liability Positions | ||
Gross Position - Liability | (184) | (262) |
Netting adjustment | 74 | 192 |
Net Position - Liability | (110) | (70) |
Other current assets | ||
Derivative Asset Positions | ||
Gross Position - Asset | 376 | 443 |
Net Position - Asset | 199 | 181 |
Derivative Liability Positions | ||
Gross Position - Liability | (67) | (182) |
Other long-term assets, net | ||
Derivative Asset Positions | ||
Gross Position - Asset | 59 | 34 |
Net Position - Asset | 54 | 27 |
Derivative Liability Positions | ||
Gross Position - Liability | (5) | (7) |
Other current liabilities | ||
Derivative Asset Positions | ||
Gross Position - Asset | 2 | |
Derivative Liability Positions | ||
Gross Position - Liability | (79) | (20) |
Net Position - Liability | (77) | (20) |
Other long-term liabilities and deferred credits | ||
Derivative Asset Positions | ||
Gross Position - Asset | 3 | |
Derivative Liability Positions | ||
Gross Position - Liability | (33) | (53) |
Net Position - Liability | $ (33) | $ (50) |
Derivatives and Risk Managem_10
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Level 3 | |||||
Rollforward of Level 3 Net Asset/(Liability) | |||||
Beginning Balance | $ (26) | $ (18) | $ (24) | $ (30) | |
Net gains/(losses) for the period included in earnings | 4 | (5) | 21 | 2 | |
Settlements | 1 | (10) | 7 | ||
Derivatives entered into during the period | (18) | (26) | (2) | ||
Ending Balance | (39) | (23) | (39) | $ (23) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | (14) | $ (5) | (5) | ||
Recurring Fair Value Measures | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 253 | 253 | $ 218 | ||
Recurring Fair Value Measures | Commodity Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 337 | 337 | 270 | ||
Recurring Fair Value Measures | Interest Rate Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (64) | (64) | (7) | ||
Recurring Fair Value Measures | Foreign Currency Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (1) | (1) | (9) | ||
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (19) | (19) | (36) | ||
Recurring Fair Value Measures | Level 1 | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 167 | 167 | 171 | ||
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 167 | 167 | 171 | ||
Recurring Fair Value Measures | Level 2 | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 125 | 125 | 71 | ||
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | 190 | 190 | 87 | ||
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (64) | (64) | (7) | ||
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (1) | (1) | (9) | ||
Recurring Fair Value Measures | Level 3 | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (39) | (39) | (24) | ||
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | (20) | (20) | 12 | ||
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | |||||
Recurring Fair Value Measurements | |||||
Total net derivative asset/(liability) | $ (19) | $ (19) | $ (36) |
Leases - Narrative Information
Leases - Narrative Information (Details) | 9 Months Ended |
Sep. 30, 2019 | |
Minimum | |
Lessee, Lease, Description [Line Items] | |
Lessee, operating and finance lease term | 1 year |
Lessee, operating and finance leases, optional renewal term | 1 year |
Maximum | |
Lessee, Lease, Description [Line Items] | |
Lessee, operating and finance lease term | 60 years |
Lessee, operating and finance leases, optional renewal term | 40 years |
Leases - Lease Costs (Details)
Leases - Lease Costs (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Leases [Abstract] | ||
Operating lease cost | $ 32 | $ 95 |
Short-term lease cost | 11 | 32 |
Other | (1) | |
Total lease cost | $ 42 | $ 127 |
Leases - Other Information (Det
Leases - Other Information (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Leases [Abstract] | |
Operating cash flows for operating leases | $ 101 |
Financing cash flows for finance leases | 13 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, operating leases | 16 |
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases | $ 10 |
Weighted-average remaining lease term (in years) | |
Operating leases, weighted-average lease term | 10 years 2 months 12 days |
Finance leases, weighted average lease term | 3 years 7 months 6 days |
Weighted-average discount rate | |
Operating leases, weighted-average discount rate | 4.50% |
Finance leases, weighted-average discount rate | 2.40% |
Leases - Assets and Liabilities
Leases - Assets and Liabilities (Details) $ in Millions | Sep. 30, 2019USD ($) |
Lessee, Lease, Assets and Liabilities [Line Items] | |
Long-term operating lease right-of-use assets, net | $ 443 |
Total lease right-of-use assets | 538 |
Operating leases | |
Long-term operating lease liabilities | 348 |
Total operating lease liabilities | 451 |
Finance Leases | |
Total finance lease liabilities | 56 |
Total lease liabilities | 507 |
Property and equipment | |
Lessee, Lease, Assets and Liabilities [Line Items] | |
Finance lease right-of-use assets, gross | 110 |
Accumulated depreciation | |
Lessee, Lease, Assets and Liabilities [Line Items] | |
Finance lease right-of-use assets, accumulated depreciation | (15) |
Property and equipment, net | |
Lessee, Lease, Assets and Liabilities [Line Items] | |
Finance lease right-of-use assets, net | 95 |
Other current liabilities | |
Operating leases | |
Operating lease liabilities, current | 103 |
Short-term debt | |
Finance Leases | |
Finance lease liabilities, current | 19 |
Other long-term debt, net | |
Finance Leases | |
Finance lease liabilities, noncurrent | $ 37 |
Leases - Maturity of Lease Liab
Leases - Maturity of Lease Liabilities (Details) $ in Millions | Sep. 30, 2019USD ($) |
Operating | |
Remainder of 2019 | $ 31 |
2020 | 113 |
2021 | 93 |
2022 | 78 |
2023 | 54 |
Thereafter | 247 |
Total | 616 |
Less: Present value discount | (165) |
Lease liabilities | 451 |
Finance | |
Remainder of 2019 | 5 |
2020 | 18 |
2021 | 9 |
2022 | 10 |
2023 | 7 |
Thereafter | 10 |
Total | 59 |
Less: Present value discount | (3) |
Lease liabilities | $ 56 |
Leases - Lessor Information (De
Leases - Lessor Information (Details) $ in Millions | Sep. 30, 2019USD ($) |
Lessor, Lease, Description [Line Items] | |
Remainder of 2019 | $ 5 |
2020 | 19 |
2021 | 22 |
2022 | 25 |
2023 | 21 |
Thereafter | $ 226 |
Minimum | |
Lessor, Lease, Description [Line Items] | |
Lessor, operating leases term | 2 years |
Maximum | |
Lessor, Lease, Description [Line Items] | |
Lessor, operating leases term | 23 years |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 |
Related Party Transaction [Line Items] | ||||||
Revenues from related parties | $ 205 | $ 266 | $ 661 | $ 832 | ||
Purchases and related costs from related parties | (7) | $ 157 | 93 | $ 317 | ||
Trade accounts receivable and other receivables, net from related parties | $ 165 | $ 144 | 165 | 165 | ||
Trade accounts payable to related parties | $ 105 | $ 121 | $ 105 | $ 105 | ||
Class C Shares | PAA | ||||||
Related Party Transaction [Line Items] | ||||||
Ownership interest (in shares) | 546,897,362 | 516,938,280 | ||||
Agreement To Transport Crude Oil On Pipeline Of Equity Method Investee | Equity Method Investee | ||||||
Related Party Transaction [Line Items] | ||||||
Ownership interest in unconsolidated entity | 50.00% | 50.00% | 50.00% | |||
Minimum | AAP | Principal Owner | ||||||
Related Party Transaction [Line Items] | ||||||
Limited partner interest | 10.00% |
Commitments and Contingencies
Commitments and Contingencies - Legal, Environmental or Regulatory (Details) | Oct. 07, 2019count | May 16, 2016employeecount | Jul. 31, 2019USD ($) | May 31, 2015bbl | May 31, 2018count | Sep. 30, 2019USD ($)lawsuit | Apr. 25, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 07, 2018count |
Legal, Environmental or Regulatory Matters | |||||||||
Estimated undiscounted reserve for environmental liabilities | $ 135,000,000 | $ 135,000,000 | |||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 62,000,000 | 61,000,000 | |||||||
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 | 31,000,000 | 28,000,000 | |||||||
Other long-term assets, net | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 31,000,000 | 33,000,000 | |||||||
Other current liabilities | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Estimated undiscounted reserve for environmental liabilities, short-term | 62,000,000 | 43,000,000 | |||||||
Other long-term liabilities and deferred credits | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Estimated undiscounted reserve for environmental liabilities, long-term | 73,000,000 | $ 92,000,000 | |||||||
Line 901 Incident | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Estimated undiscounted reserve for environmental liabilities | 79,000,000 | ||||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 55,000,000 | ||||||||
Estimated size of release (in bbl) | bbl | 2,934 | ||||||||
Estimated size of release to reach Pacific Ocean (in bbl) | bbl | 598 | ||||||||
Aggregate total estimated costs | 380,000,000 | ||||||||
Recoveries from insurance carriers | 200,000,000 | ||||||||
Total release costs probable of recovery | 255,000,000 | ||||||||
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 | 26,000,000 | ||||||||
Line 901 Incident | Other current liabilities | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Estimated undiscounted reserve for environmental liabilities, short-term | $ 52,000,000 | ||||||||
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 felony discharges found guilty | count | 1 | ||||||||
Number of misdemeanor charges found guilty | count | 8 | ||||||||
Number of misdemeanor charges found guilty, reporting | count | 1 | ||||||||
Number of misdemeanor charges found guilty, strict liability discharge | count | 1 | ||||||||
Number of misdemeanor charges found guilty, strict liability animal takings | count | 6 | ||||||||
Number of misdemeanor charges found not guilty, strict liability animal takings | count | 1 | ||||||||
Number of charges jury deadlocked | count | 3 | ||||||||
Number of charges jury deadlocked, felony discharges | count | 2 | ||||||||
Number of charges jury deadlocked, strict liability animal takings | count | 1 | ||||||||
Number of misdemeanor discharges dropped | count | 2 | ||||||||
Number of counts dismissed | count | 31 | ||||||||
Number of felony charges dismissed | count | 1 | ||||||||
Fines or penalties assessed | $ 3,350,000 | ||||||||
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 | ||||||||
San Joaquin Valley Air Pollution Control District | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Fines or penalties assessed | $ 597,000 | ||||||||
Reduced fine paid | $ 275,000 | ||||||||
Forecast | Line 901 Incident | May 2016 Indictment | |||||||||
Legal, Environmental or Regulatory Matters | |||||||||
Number of felony charges dismissed | count | 2 |
Operating Segments - Segment F
Operating Segments - Segment Financial Data (Details) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($)segment | Sep. 30, 2018USD ($) | |
Segment Reporting Information [Line Items] | ||||
Operating segments number | segment | 3 | |||
Revenues: | ||||
Revenues | $ 7,886 | $ 8,792 | $ 24,515 | $ 25,269 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Equity earnings in unconsolidated entities | 102 | 110 | 274 | 281 |
Segment Adjusted EBITDA | 727 | 636 | 2,371 | 1,733 |
Maintenance capital | 85 | 78 | 204 | 186 |
Transportation | ||||
Revenues: | ||||
Revenues | 196 | 161 | 581 | 458 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Equity earnings in unconsolidated entities | 102 | 110 | 274 | 281 |
Segment Adjusted EBITDA | 462 | 388 | 1,271 | 1,083 |
Maintenance capital | 42 | 41 | 110 | 102 |
Facilities | ||||
Revenues: | ||||
Revenues | 149 | 149 | 457 | 437 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Segment Adjusted EBITDA | 173 | 173 | 529 | 530 |
Maintenance capital | 28 | 33 | 74 | 74 |
Supply and Logistics | ||||
Revenues: | ||||
Revenues | 7,541 | 8,482 | 23,477 | 24,374 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||||
Segment Adjusted EBITDA | 92 | 75 | 571 | 120 |
Maintenance capital | 15 | 4 | 20 | 10 |
Operating Segments, Before Intersegment Adjustment | Transportation | ||||
Revenues: | ||||
Revenues | 319 | 292 | 938 | 808 |
Operating Segments, Before Intersegment Adjustment | Facilities | ||||
Revenues: | ||||
Revenues | 149 | 149 | 457 | 437 |
Operating Segments, Before Intersegment Adjustment | Supply and Logistics | ||||
Revenues: | ||||
Revenues | 7,541 | 8,482 | 23,477 | 24,374 |
Operating Segments | ||||
Revenues: | ||||
Revenues | 8,430 | 9,270 | 26,072 | 26,669 |
Operating Segments | Transportation | ||||
Revenues: | ||||
Revenues | 597 | 498 | 1,712 | 1,427 |
Operating Segments | Facilities | ||||
Revenues: | ||||
Revenues | 291 | 289 | 880 | 866 |
Operating Segments | Supply and Logistics | ||||
Revenues: | ||||
Revenues | 7,542 | 8,483 | 23,480 | 24,376 |
Intersegment | ||||
Revenues: | ||||
Revenues | (544) | (478) | (1,557) | (1,400) |
Intersegment | Transportation | ||||
Revenues: | ||||
Revenues | (278) | (206) | (774) | (619) |
Intersegment | Facilities | ||||
Revenues: | ||||
Revenues | (142) | (140) | (423) | (429) |
Intersegment | Supply and Logistics | ||||
Revenues: | ||||
Revenues | (1) | (1) | (3) | (2) |
Intersegment Adjustment | ||||
Revenues: | ||||
Revenues | $ (123) | $ (131) | $ (357) | $ (350) |
Operating Segments - Segment A
Operating Segments - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Segment Reporting, Reconciling Item from Segments to Consolidated [Line Items] | ||||
Segment Adjusted EBITDA | $ 727 | $ 636 | $ 2,371 | $ 1,733 |
Adjustments: | ||||
Depreciation and amortization of unconsolidated entities | (18) | (15) | (45) | (44) |
Gains/(losses) from derivative activities, net of inventory valuation adjustments | 29 | 110 | 60 | (107) |
Long-term inventory costing adjustments | 1 | 10 | (3) | 18 |
Deficiencies under minimum volume commitments, net | 4 | 4 | 10 | (9) |
Equity-indexed compensation expense | (5) | (14) | (13) | (37) |
Net gain/(loss) on foreign currency revaluation | 5 | 3 | (7) | (5) |
Unallocated general and administrative expenses | (75) | (75) | (229) | (235) |
Depreciation and amortization | (157) | (129) | (441) | (386) |
Gains/(losses) on asset sales and asset impairments, net | 7 | (2) | 7 | 79 |
Gain on investment in unconsolidated entities | 4 | 210 | 271 | 210 |
Interest expense, net | (108) | (110) | (311) | (327) |
Other income/(expense), net | 5 | (3) | 23 | 8 |
INCOME BEFORE TAX | 493 | 699 | 1,908 | 1,130 |
Income tax expense | (62) | (23) | (137) | (84) |
NET INCOME | 431 | 676 | 1,771 | 1,046 |
Net income attributable to noncontrolling interests | (361) | (565) | (1,488) | (892) |
NET INCOME ATTRIBUTABLE TO PAGP | 70 | 111 | 283 | 154 |
Unallocated | ||||
Adjustments: | ||||
Unallocated general and administrative expenses | $ (1) | $ (1) | (4) | $ (3) |
Line 901 Incident | ||||
Adjustments: | ||||
Line 901 incident | $ (10) |
Income Taxes (Details)
Income Taxes (Details) - Alberta Government - USD ($) $ in Millions | 3 Months Ended | 30 Months Ended |
Jun. 30, 2019 | Jan. 01, 2022 | |
Income Tax Examination [Line Items] | ||
Alberta provincial corporate income tax rate | 12.00% | |
Deferred tax benefit from change in tax rate | $ 60 | |
Forecast | ||
Income Tax Examination [Line Items] | ||
Alberta provincial corporate income tax rate | 8.00% |