Delaware | 90-1005472 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
333 Clay Street, Suite 1600, Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer ý | Accelerated filer o | |
Non-accelerated filer o | Smaller reporting company o | |
(Do not check if a smaller reporting company) | Emerging growth company o |
Page | |
March 31, 2017 | December 31, 2016 | ||||||
(unaudited) | |||||||
ASSETS | |||||||
CURRENT ASSETS | |||||||
Cash and cash equivalents | $ | 41 | $ | 50 | |||
Trade accounts receivable and other receivables, net | 2,218 | 2,279 | |||||
Inventory | 1,219 | 1,343 | |||||
Other current assets | 736 | 603 | |||||
Total current assets | 4,214 | 4,275 | |||||
PROPERTY AND EQUIPMENT | 16,509 | 16,261 | |||||
Accumulated depreciation | (2,432 | ) | (2,371 | ) | |||
Property and equipment, net | 14,077 | 13,890 | |||||
OTHER ASSETS | |||||||
Goodwill | 2,596 | 2,344 | |||||
Investments in unconsolidated entities | 2,469 | 2,343 | |||||
Deferred tax asset | 2,221 | 1,876 | |||||
Linefill and base gas | 883 | 896 | |||||
Long-term inventory | 131 | 193 | |||||
Other long-term assets, net | 917 | 286 | |||||
Total assets | $ | 27,508 | $ | 26,103 | |||
LIABILITIES AND PARTNERS’ CAPITAL | |||||||
CURRENT LIABILITIES | |||||||
Accounts payable and accrued liabilities | $ | 2,475 | $ | 2,590 | |||
Short-term debt | 1,341 | 1,715 | |||||
Other current liabilities | 342 | 361 | |||||
Total current liabilities | 4,158 | 4,666 | |||||
LONG-TERM LIABILITIES | |||||||
Senior notes, net of unamortized discounts and debt issuance costs | 9,876 | 9,874 | |||||
Other long-term debt | 3 | 250 | |||||
Other long-term liabilities and deferred credits | 644 | 606 | |||||
Total long-term liabilities | 10,523 | 10,730 | |||||
COMMITMENTS AND CONTINGENCIES (NOTE 12) | |||||||
PARTNERS’ CAPITAL | |||||||
Class A Shareholders (151,779,960 and 101,206,526 shares outstanding, respectively) | 2,604 | 1,737 | |||||
Noncontrolling interests | 10,223 | 8,970 | |||||
Total partners’ capital | 12,827 | 10,707 | |||||
Total liabilities and partners’ capital | $ | 27,508 | $ | 26,103 |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
(unaudited) | |||||||
REVENUES | |||||||
Supply and Logistics segment revenues | $ | 6,395 | $ | 3,819 | |||
Transportation segment revenues | 138 | 154 | |||||
Facilities segment revenues | 134 | 138 | |||||
Total revenues | 6,667 | 4,111 | |||||
COSTS AND EXPENSES | |||||||
Purchases and related costs | 5,593 | 3,348 | |||||
Field operating costs | 288 | 300 | |||||
General and administrative expenses | 75 | 68 | |||||
Depreciation and amortization | 122 | 114 | |||||
Total costs and expenses | 6,078 | 3,830 | |||||
OPERATING INCOME | 589 | 281 | |||||
OTHER INCOME/(EXPENSE) | |||||||
Equity earnings in unconsolidated entities | 53 | 47 | |||||
Interest expense (net of capitalized interest of $6 and $13, respectively) | (129 | ) | (116 | ) | |||
Other income/(expense), net | (5 | ) | 5 | ||||
INCOME BEFORE TAX | 508 | 217 | |||||
Current income tax expense | (10 | ) | (31 | ) | |||
Deferred income tax expense | (96 | ) | (9 | ) | |||
NET INCOME | 402 | 177 | |||||
Net income attributable to noncontrolling interests | (361 | ) | (141 | ) | |||
NET INCOME ATTRIBUTABLE TO PAGP | $ | 41 | $ | 36 | |||
BASIC NET INCOME PER CLASS A SHARE | $ | 0.34 | $ | 0.39 | |||
DILUTED NET INCOME PER CLASS A SHARE | $ | 0.34 | $ | 0.37 | |||
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING | 120 | 95 | |||||
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING | 120 | 245 |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
(unaudited) | |||||||
Net income | $ | 402 | $ | 177 | |||
Other comprehensive income | 36 | 118 | |||||
Comprehensive income | 438 | 295 | |||||
Comprehensive income attributable to noncontrolling interests | (392 | ) | (258 | ) | |||
Comprehensive income attributable to PAGP | $ | 46 | $ | 37 |
Derivative Instruments | Translation Adjustments | Other | Total | ||||||||||||
(unaudited) | |||||||||||||||
Balance at December 31, 2016 | $ | (228 | ) | $ | (782 | ) | $ | 1 | $ | (1,009 | ) | ||||
Reclassification adjustments | 2 | — | — | 2 | |||||||||||
Deferred gain on cash flow hedges | 7 | — | — | 7 | |||||||||||
Currency translation adjustments | — | 27 | — | 27 | |||||||||||
Total period activity | 9 | 27 | — | 36 | |||||||||||
Balance at March 31, 2017 | $ | (219 | ) | $ | (755 | ) | $ | 1 | $ | (973 | ) |
Derivative Instruments | Translation Adjustments | Total | |||||||||
(unaudited) | |||||||||||
Balance at December 31, 2015 | $ | (203 | ) | $ | (878 | ) | $ | (1,081 | ) | ||
Reclassification adjustments | 1 | — | 1 | ||||||||
Deferred loss on cash flow hedges | (90 | ) | — | (90 | ) | ||||||
Currency translation adjustments | — | 207 | 207 | ||||||||
Total period activity | (89 | ) | 207 | 118 | |||||||
Balance at March 31, 2016 | $ | (292 | ) | $ | (671 | ) | $ | (963 | ) |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
(unaudited) | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||
Net income | $ | 402 | $ | 177 | |||
Reconciliation of net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 122 | 114 | |||||
Equity-indexed compensation expense | 12 | 4 | |||||
Deferred income tax expense | 96 | 9 | |||||
(Gain)/loss on foreign currency revaluation | (3 | ) | (3 | ) | |||
Equity earnings in unconsolidated entities | (53 | ) | (47 | ) | |||
Distributions from unconsolidated entities | 52 | 52 | |||||
Other | 10 | 7 | |||||
Changes in assets and liabilities, net of acquisitions | 177 | 318 | |||||
Net cash provided by operating activities | 815 | 631 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||
Cash paid in connection with acquisitions, net of cash acquired | (1,254 | ) | (85 | ) | |||
Investments in unconsolidated entities | (123 | ) | (75 | ) | |||
Additions to property, equipment and other | (275 | ) | (372 | ) | |||
Proceeds from sales of assets | 161 | 246 | |||||
Other investing activities | — | (1 | ) | ||||
Net cash used in investing activities | (1,491 | ) | (287 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||
Net borrowings/(repayments) under PAA commercial paper program (Note 8) | 149 | (1,211 | ) | ||||
Net repayments under PAA senior secured hedged inventory facility (Note 8) | (501 | ) | (300 | ) | |||
Net borrowings under AAP senior secured revolving credit facility | — | 34 | |||||
Repayments of PAA senior notes (Note 8) | (400 | ) | — | ||||
Net proceeds from the sale of Class A shares (Note 9) | 1,535 | — | |||||
Net proceeds from the sale of Series A preferred units by a subsidiary | — | 1,570 | |||||
Net proceeds from the sale of common units by a subsidiary (Note 9) | 129 | — | |||||
Distributions paid to Class A shareholders (Note 9) | (57 | ) | (55 | ) | |||
Distributions paid to noncontrolling interests (Note 9) | (315 | ) | (375 | ) | |||
Other financing activities | 127 | (1 | ) | ||||
Net cash provided by/(used in) financing activities | 667 | (338 | ) | ||||
Effect of translation adjustment on cash | — | 4 | |||||
Net increase/(decrease) in cash and cash equivalents | (9 | ) | 10 | ||||
Cash and cash equivalents, beginning of period | 50 | 30 | |||||
Cash and cash equivalents, end of period | $ | 41 | $ | 40 | |||
Cash paid for: | |||||||
Interest, net of amounts capitalized | $ | 92 | $ | 88 | |||
Income taxes, net of amounts refunded | $ | 27 | $ | 16 |
Class A Shareholders | Noncontrolling Interests | Total Partners’ Capital | |||||||||
(unaudited) | |||||||||||
Balance at December 31, 2016 | $ | 1,737 | $ | 8,970 | $ | 10,707 | |||||
Net income | 41 | 361 | 402 | ||||||||
Cash distributions to partners | (57 | ) | (315 | ) | (372 | ) | |||||
Deferred tax asset (Note 9) | 386 | — | 386 | ||||||||
Sales of Class A shares (Note 9) | 462 | 1,073 | 1,535 | ||||||||
Sales of common units by a subsidiary (Note 9) | 13 | 116 | 129 | ||||||||
Other comprehensive income | 5 | 31 | 36 | ||||||||
Other | 17 | (13 | ) | 4 | |||||||
Balance at March 31, 2017 | $ | 2,604 | $ | 10,223 | $ | 12,827 |
Class A Shareholders | Noncontrolling Interests | Total Partners’ Capital | |||||||||
(unaudited) | |||||||||||
Balance at December 31, 2015 | $ | 1,762 | $ | 7,472 | $ | 9,234 | |||||
Net income | 36 | 141 | 177 | ||||||||
Cash distributions to partners | (55 | ) | (375 | ) | (430 | ) | |||||
Deferred tax asset | 94 | — | 94 | ||||||||
Change in ownership interest in connection with Exchange Right exercises | (17 | ) | 17 | — | |||||||
Sale of Series A preferred units by a subsidiary | — | 1,509 | 1,509 | ||||||||
Other comprehensive income | 1 | 117 | 118 | ||||||||
Other | — | 3 | 3 | ||||||||
Balance at March 31, 2016 | $ | 1,821 | $ | 8,884 | $ | 10,705 |
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 |
LIBOR | = | London Interbank Offered Rate |
LTIP | = | Long-term incentive plan |
Mcf | = | Thousand cubic feet |
NGL | = | Natural gas liquids, including ethane, propane and butane |
NYMEX | = | New York Mercantile Exchange |
Oxy | = | Occidental Petroleum Corporation or its subsidiaries |
PLA | = | Pipeline loss allowance |
SEC | = | United States Securities and Exchange Commission |
USD | = | United States dollar |
WTI | = | West Texas Intermediate |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Basic Net Income per Class A Share | |||||||
Net income attributable to PAGP | $ | 41 | $ | 36 | |||
Basic weighted average Class A shares outstanding | 120 | 95 | |||||
Basic net income per Class A share | $ | 0.34 | $ | 0.39 | |||
Diluted Net Income per Class A Share | |||||||
Net income attributable to PAGP | $ | 41 | $ | 36 | |||
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units | — | 54 | |||||
Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units | $ | 41 | $ | 90 | |||
Basic weighted average Class A shares outstanding | 120 | 95 | |||||
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units | — | 150 | |||||
Diluted weighted average Class A shares outstanding | 120 | 245 | |||||
Diluted net income per Class A share | $ | 0.34 | $ | 0.37 |
March 31, 2017 | December 31, 2016 | |||||||||||||||||||||||||
Volumes | Unit of Measure | Carrying Value | Price/ Unit (1) | Volumes | Unit of Measure | Carrying Value | Price/ Unit (1) | |||||||||||||||||||
Inventory | ||||||||||||||||||||||||||
Crude oil | 21,710 | barrels | $ | 1,071 | $ | 49.33 | 23,589 | barrels | $ | 1,049 | $ | 44.47 | ||||||||||||||
NGL | 5,396 | barrels | 120 | $ | 22.24 | 13,497 | barrels | 242 | $ | 17.93 | ||||||||||||||||
Natural gas | 3,630 | Mcf | 10 | $ | 2.75 | 14,540 | Mcf | 32 | $ | 2.20 | ||||||||||||||||
Other | N/A | 18 | N/A | N/A | 20 | N/A | ||||||||||||||||||||
Inventory subtotal | 1,219 | 1,343 | ||||||||||||||||||||||||
Linefill and base gas | ||||||||||||||||||||||||||
Crude oil | 12,679 | barrels | 729 | $ | 57.50 | 12,273 | barrels | 710 | $ | 57.85 | ||||||||||||||||
NGL | 1,646 | barrels | 46 | $ | 27.95 | 1,660 | barrels | 45 | $ | 27.11 | ||||||||||||||||
Natural gas | 24,976 | Mcf | 108 | $ | 4.32 | 30,812 | Mcf | 141 | $ | 4.58 | ||||||||||||||||
Linefill and base gas subtotal | 883 | 896 | ||||||||||||||||||||||||
Long-term inventory | ||||||||||||||||||||||||||
Crude oil | 2,345 | barrels | 101 | $ | 43.07 | 3,279 | barrels | 163 | $ | 49.71 | ||||||||||||||||
NGL | 1,418 | barrels | 30 | $ | 21.16 | 1,418 | barrels | 30 | $ | 21.16 | ||||||||||||||||
Long-term inventory subtotal | 131 | 193 | ||||||||||||||||||||||||
Total | $ | 2,233 | $ | 2,432 |
(1) | Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. |
Identifiable assets acquired and liabilities assumed: | Estimated Useful Lives (Years) | Recognized amount | ||||
Property and equipment | 3 - 70 | $ | 299 | |||
Intangible assets | 20 | 641 | ||||
Goodwill | N/A | 278 | ||||
Other (including $4 million of cash acquired) | N/A | (1 | ) | |||
$ | 1,217 |
Remainder of 2017 | $ | 9 | ||
2018 | $ | 25 | ||
2019 | $ | 34 | ||
2020 | $ | 42 | ||
2021 | $ | 48 |
Transportation | Facilities | Supply and Logistics | Total | ||||||||||||
Balance at December 31, 2016 | $ | 806 | $ | 1,034 | $ | 504 | $ | 2,344 | |||||||
Acquisitions (1) | 278 | — | — | 278 | |||||||||||
Foreign currency translation adjustments | 2 | 1 | — | 3 | |||||||||||
Dispositions and reclassifications to assets held for sale | — | (29 | ) | — | (29 | ) | |||||||||
Balance at March 31, 2017 | $ | 1,086 | $ | 1,006 | $ | 504 | $ | 2,596 |
(1) | Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized. |
March 31, 2017 | December 31, 2016 | ||||||
SHORT-TERM DEBT | |||||||
PAA commercial paper notes, bearing a weighted-average interest rate of 1.9% and 1.6%, respectively (1) | $ | 958 | $ | 563 | |||
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.0% and 1.8%, respectively (1) | 250 | 750 | |||||
PAA senior notes: | |||||||
6.13% senior notes due January 2017 | — | 400 | |||||
Other | 133 | 2 | |||||
Total short-term debt (2) | 1,341 | 1,715 | |||||
LONG-TERM DEBT | |||||||
PAA senior notes, net of unamortized discounts and debt issuance costs of $74 and $76, respectively | 9,876 | 9,874 | |||||
PAA commercial paper notes, bearing a weighted-average interest rate of 1.6% (3) | — | 247 | |||||
Other | 3 | 3 | |||||
Total long-term debt | 9,879 | 10,124 | |||||
Total debt (4) | $ | 11,220 | $ | 11,839 |
(1) | We classified these PAA commercial paper notes and credit facility borrowings as short-term as of March 31, 2017 and December 31, 2016, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. |
(2) | As of March 31, 2017 and December 31, 2016, balance includes borrowings of $95 million and $410 million, respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. |
(3) | At December 31, 2016, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis. |
(4) | PAA’s fixed-rate senior notes (including current maturities) had a face value of approximately $9.9 billion and $10.3 billion as of March 31, 2017 and December 31, 2016, respectively. We estimated the aggregate fair value of these notes as of March 31, 2017 and December 31, 2016 to be approximately $10.1 billion and $10.4 billion, respectively. 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 the credit facilities and the PAA commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for the PAA senior notes, the credit facilities and the PAA commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. |
Class A Shares | Class B Shares | Class C Shares | ||||||
Outstanding at December 31, 2016 | 101,206,526 | 138,043,486 | 491,910,863 | |||||
Conversion of AAP Management Units (1) | — | 276,405 | — | |||||
Exchange Right exercises (1) | 479,298 | (479,298 | ) | — | ||||
Redemption Right exercises (1) | — | (3,454,374 | ) | 3,454,374 | ||||
Sales of Class A shares | 50,086,326 | — | — | |||||
Sales of common units by a subsidiary | — | — | 4,033,567 | |||||
Issuance of Series A preferred units by a subsidiary | — | — | 1,287,773 | |||||
Other | 7,810 | — | 82,872 | |||||
Outstanding at March 31, 2017 | 151,779,960 | 134,386,219 | 500,769,449 |
Class A Shares | Class B Shares | ||||
Outstanding at December 31, 2015 | 86,099,037 | 141,485,588 | |||
Conversion of AAP Management Units (1) | — | 6,742,383 | |||
Exchange Right exercises (1) | 14,065,812 | (14,065,812 | ) | ||
Issuance of Class A shares under LTIP | 7,811 | — | |||
Outstanding at March 31, 2016 | 100,172,660 | 134,162,159 |
(1) | See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional discussion regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights. |
Distribution Payment Date | Distributions to Class A Shareholders | Distributions per Class A Share | ||||||
May 15, 2017 (1) | $ | 84 | $ | 0.55 | ||||
February 14, 2017 | $ | 57 | $ | 0.55 |
(1) | Payable to shareholders of record at the close of business on May 1, 2017 for the period January 1, 2017 through March 31, 2017. |
Type of Offering | Class A Shares Issued | Net Proceeds (1) | ||||||
Continuous Offering Program | 1,786,326 | $ | 61 | (2) | ||||
Underwritten Offering | 48,300,000 | 1,474 | ||||||
50,086,326 | $ | 1,535 |
(2) | We pay commissions to our sales agents in connection with issuances of Class A shares under our Continuous Offering Program. We paid $1 million of such commissions during the three months ended March 31, 2017. |
Distributions | Cash Distribution per Common Unit | ||||||||||||||||
Common Unitholders | Total Cash Distribution | ||||||||||||||||
Distribution Payment Date | Public | AAP | |||||||||||||||
May 15, 2017 (1) | $ | 240 | $ | 159 | $ | 399 | $ | 0.55 | |||||||||
February 14, 2017 | $ | 237 | $ | 134 | $ | 371 | $ | 0.55 |
(1) | Payable to unitholders of record at the close of business on May 1, 2017 for the period January 1, 2017 through March 31, 2017. |
Distribution to AAP's Partners | ||||||||||||
Distribution Payment Date | Noncontrolling Interests | PAGP | Total Cash Distributions | |||||||||
May 15, 2017 (1) | $ | 75 | $ | 84 | $ | 159 | ||||||
February 14, 2017 | $ | 77 | $ | 57 | $ | 134 |
(1) | Payable to unitholders of record at the close of business on May 1, 2017 for the period January 1, 2017 through March 31, 2017. |
• | A net long position of 2.6 million barrels associated with our crude oil purchases, which was unwound ratably during April 2017 to match monthly average pricing. |
• | A net short time spread position of 4.6 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through July 2018. |
• | A crude oil grade basis position of 42.1 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials. |
• | A net short position of 3.5 Bcf through April 2017 related to anticipated sales of natural gas inventory. |
• | A net short position of 24.0 million barrels through December 2019 related to anticipated net sales of our crude oil and NGL inventory. |
Hedged Transaction | Number and Types of Derivatives Employed | Notional Amount | Expected Termination Date | Average Rate Locked | Accounting Treatment | ||||||||
Anticipated interest payments | 8 forward starting swaps (30-year) | $ | 200 | 6/15/2017 | 3.14 | % | Cash flow hedge | ||||||
Anticipated interest payments | 8 forward starting swaps (30-year) | $ | 200 | 6/15/2018 | 3.20 | % | Cash flow hedge | ||||||
Anticipated interest payments | 8 forward starting swaps (30-year) | $ | 200 | 6/14/2019 | 2.83 | % | Cash flow hedge |
USD | CAD | Average Exchange Rate USD to CAD | ||||||||||
Forward exchange contracts that exchange CAD for USD: | ||||||||||||
2017 | $ | 175 | $ | 234 | $1.00 - $1.34 | |||||||
Forward exchange contracts that exchange USD for CAD: | ||||||||||||
2017 | $ | 428 | $ | 569 | $1.00 - $1.33 |
Three Months Ended March 31, 2017 | Three Months Ended March 31, 2016 | ||||||||||||||||||||||||
Location of Gain/(Loss) | Derivatives in Hedging Relationships | Derivatives Not Designated as a Hedge | Total | Derivatives in Hedging Relationships | Derivatives Not Designated as a Hedge | Total | |||||||||||||||||||
Commodity Derivatives | |||||||||||||||||||||||||
Supply and Logistics segment revenues | $ | — | $ | 96 | $ | 96 | $ | 1 | $ | 31 | $ | 32 | |||||||||||||
Transportation segment revenues | — | — | — | — | 2 | 2 | |||||||||||||||||||
Field operating costs | — | (3 | ) | (3 | ) | — | (2 | ) | (2 | ) | |||||||||||||||
Interest Rate Derivatives | |||||||||||||||||||||||||
Interest expense, net | (2 | ) | — | (2 | ) | (2 | ) | — | (2 | ) | |||||||||||||||
Foreign Currency Derivatives | |||||||||||||||||||||||||
Supply and Logistics segment revenues | — | 2 | 2 | — | 6 | 6 | |||||||||||||||||||
Preferred Distribution Rate Reset Option | |||||||||||||||||||||||||
Other income/(expense), net | — | (4 | ) | (4 | ) | — | — | — | |||||||||||||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income | $ | (2 | ) | $ | 91 | $ | 89 | $ | (1 | ) | $ | 37 | $ | 36 |
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||
Derivatives designated as hedging instruments: | ||||||||||||
Commodity derivatives | $ | — | Other current assets | $ | — | |||||||
Interest rate derivatives | — | Other current liabilities | (20 | ) | ||||||||
Other long-term liabilities and deferred credits | (23 | ) | ||||||||||
Total derivatives designated as hedging instruments | $ | — | $ | (43 | ) | |||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity derivatives | Other current assets | $ | 79 | Other current assets | $ | (81 | ) | |||||
Other long-term assets, net | 13 | Other long-term assets, net | (8 | ) | ||||||||
Other current liabilities | 2 | Other current liabilities | (7 | ) | ||||||||
Other long-term liabilities and deferred credits | (4 | ) | ||||||||||
Foreign currency derivatives | Other current assets | 1 | Other current liabilities | (4 | ) | |||||||
Other current liabilities | 1 | |||||||||||
Preferred Distribution Rate Reset Option | — | Other long-term liabilities and deferred credits | (36 | ) | ||||||||
Total derivatives not designated as hedging instruments | $ | 96 | $ | (140 | ) | |||||||
Total derivatives | $ | 96 | $ | (183 | ) |
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||
Derivatives designated as hedging instruments: | ||||||||||||
Commodity derivatives | $ | — | Other current assets | $ | — | |||||||
Interest rate derivatives | — | Other current liabilities | (23 | ) | ||||||||
Other long-term liabilities and deferred credits | (27 | ) | ||||||||||
Total derivatives designated as hedging instruments | $ | — | $ | (50 | ) | |||||||
Derivatives not designated as hedging instruments: | ||||||||||||
Commodity derivatives | Other current assets | $ | 101 | Other current assets | $ | (344 | ) | |||||
Other long-term assets, net | 2 | Other long-term assets, net | (1 | ) | ||||||||
Other long-term liabilities and deferred credits | 2 | Other current liabilities | (14 | ) | ||||||||
Other long-term liabilities and deferred credits | (34 | ) | ||||||||||
Foreign currency derivatives | Other current liabilities | 3 | Other current liabilities | (6 | ) | |||||||
Preferred Distribution Rate Reset Option | — | Other long-term liabilities and deferred credits | (32 | ) | ||||||||
Total derivatives not designated as hedging instruments | $ | 108 | $ | (431 | ) | |||||||
Total derivatives | $ | 108 | $ | (481 | ) |
March 31, 2017 | December 31, 2016 | ||||||
Initial margin | $ | 92 | $ | 119 | |||
Variation margin posted/(returned) | 3 | 291 | |||||
Net broker receivable/(payable) | $ | 95 | $ | 410 |
March 31, 2017 | December 31, 2016 | |||||||||||||||
Derivative Asset Positions | Derivative Liability Positions | Derivative Asset Positions | Derivative Liability Positions | |||||||||||||
Netting Adjustments: | ||||||||||||||||
Gross position - asset/(liability) | $ | 96 | $ | (183 | ) | $ | 108 | $ | (481 | ) | ||||||
Netting adjustment | (92 | ) | 92 | (350 | ) | 350 | ||||||||||
Cash collateral paid/(received) | 95 | — | 410 | — | ||||||||||||
Net position - asset/(liability) | $ | 99 | $ | (91 | ) | $ | 168 | $ | (131 | ) | ||||||
Balance Sheet Location After Netting Adjustments: | ||||||||||||||||
Other current assets | $ | 94 | $ | — | $ | 167 | $ | — | ||||||||
Other long-term assets, net | 5 | — | 1 | — | ||||||||||||
Other current liabilities | — | (28 | ) | — | (40 | ) | ||||||||||
Other long-term liabilities and deferred credits | — | (63 | ) | — | (91 | ) | ||||||||||
$ | 99 | $ | (91 | ) | $ | 168 | $ | (131 | ) |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Interest rate derivatives, net | $ | 7 | $ | (90 | ) |
Fair Value as of March 31, 2017 | Fair Value as of December 31, 2016 | ||||||||||||||||||||||||||||||||
Recurring Fair Value Measures (1) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
Commodity derivatives | $ | (6 | ) | $ | — | $ | — | $ | (6 | ) | $ | (113 | ) | $ | (171 | ) | $ | (4 | ) | $ | (288 | ) | |||||||||||
Interest rate derivatives | — | (43 | ) | — | (43 | ) | — | (50 | ) | — | (50 | ) | |||||||||||||||||||||
Foreign currency derivatives | — | (2 | ) | — | (2 | ) | — | (3 | ) | — | (3 | ) | |||||||||||||||||||||
Preferred Distribution Rate Reset Option | — | — | (36 | ) | (36 | ) | — | — | (32 | ) | (32 | ) | |||||||||||||||||||||
Total net derivative asset/(liability) | $ | (6 | ) | $ | (45 | ) | $ | (36 | ) | $ | (87 | ) | $ | (113 | ) | $ | (224 | ) | $ | (36 | ) | $ | (373 | ) |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Beginning Balance | $ | (36 | ) | $ | 11 | ||
Net losses for the period included in earnings | (3 | ) | (1 | ) | |||
Settlements | 3 | (9 | ) | ||||
Derivatives entered into during the period | — | (60 | ) | ||||
Ending Balance | $ | (36 | ) | $ | (59 | ) | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | $ | (2 | ) | $ | (1 | ) |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Revenues | $ | 234 | $ | 112 | |||
Purchases and related costs (1) | $ | (40 | ) | $ | (46 | ) |
(1) | Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed Consolidated Statements of Operations. |
March 31, 2017 | December 31, 2016 | ||||||
Trade accounts receivable and other receivables | $ | 872 | $ | 789 | |||
Accounts payable | $ | 818 | $ | 836 |
Three Months Ended March 31, 2017 | Transportation | Facilities | Supply and Logistics | Intersegment Adjustment (1) | Total | |||||||||||||||
Revenues: | ||||||||||||||||||||
External customers | $ | 225 | $ | 134 | $ | 6,395 | $ | (87 | ) | $ | 6,667 | |||||||||
Intersegment (2) | 164 | 159 | 5 | 87 | 415 | |||||||||||||||
Total revenues of reportable segments | $ | 389 | $ | 293 | $ | 6,400 | $ | — | $ | 7,082 | ||||||||||
Equity earnings in unconsolidated entities | $ | 53 | $ | — | $ | — | $ | 53 | ||||||||||||
Segment adjusted EBITDA | $ | 273 | $ | 188 | $ | 51 | $ | 512 | ||||||||||||
Maintenance capital | $ | 29 | $ | 27 | $ | 3 | $ | 59 |
Three Months Ended March 31, 2016 | Transportation | Facilities | Supply and Logistics | Intersegment Adjustment (1) | Total | |||||||||||||||
Revenues: | ||||||||||||||||||||
External customers | $ | 241 | $ | 138 | $ | 3,819 | $ | (87 | ) | $ | 4,111 | |||||||||
Intersegment (2) | 142 | 127 | 2 | 87 | 358 | |||||||||||||||
Total revenues of reportable segments | $ | 383 | $ | 265 | $ | 3,821 | $ | — | $ | 4,469 | ||||||||||
Equity earnings in unconsolidated entities | $ | 47 | $ | — | $ | — | $ | 47 | ||||||||||||
Segment adjusted EBITDA | $ | 281 | $ | 167 | $ | 184 | $ | 632 | ||||||||||||
Maintenance capital | $ | 35 | $ | 9 | $ | 3 | $ | 47 |
(1) | Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM. |
(2) | Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated. |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Segment adjusted EBITDA | $ | 512 | $ | 632 | |||
Adjustments (1): | |||||||
Depreciation and amortization of unconsolidated entities (2) | (14 | ) | (12 | ) | |||
Gains/(losses) from derivative activities net of inventory valuation adjustments (3) | 289 | (122 | ) | ||||
Long-term inventory costing adjustments (4) | (7 | ) | (23 | ) | |||
Deficiencies under minimum volume commitments, net (5) | (11 | ) | (27 | ) | |||
Equity-indexed compensation expense (6) | (3 | ) | (4 | ) | |||
Net gain/(loss) on foreign currency revaluation (7) | 4 | (1 | ) | ||||
Significant acquisition-related expenses (8) | (5 | ) | — | ||||
Unallocated general and administrative expenses | (1 | ) | (1 | ) | |||
Depreciation and amortization | (122 | ) | (114 | ) | |||
Interest expense, net | (129 | ) | (116 | ) | |||
Other income/(expense), net | (5 | ) | 5 | ||||
Income before tax | 508 | 217 | |||||
Income tax expense | (106 | ) | (40 | ) | |||
Net income | 402 | 177 | |||||
Net income attributable to noncontrolling interests | (361 | ) | (141 | ) | |||
Net income attributable to PAGP | $ | 41 | $ | 36 |
(1) | Represents adjustments utilized by our CODM in the evaluation of segment results. |
(2) | Includes our proportionate share of the depreciation and amortization of equity method investments. |
(3) | We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. |
(4) | We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA. |
(5) | We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. |
(6) | Includes equity-indexed compensation expense associated with awards that will or may be settled in PAA common units. |
(7) | Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities. |
(8) | Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the three months ended March 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance. Acquisition-related expenses for the 2016 period were not significant to segment adjusted EBITDA. |
• | Executive Summary |
• | Acquisitions and Capital Projects |
• | Results of Operations |
• | Outlook |
• | Liquidity and Capital Resources |
• | Off-Balance Sheet Arrangements |
• | Recent Accounting Pronouncements |
• | Critical Accounting Policies and Estimates |
• | Forward-Looking Statements |
• | The favorable impact of gains on certain derivative instruments and contributions from our recently completed acquisitions and capital expansion projects, partially offset by less favorable crude oil and NGL market conditions and margin compression caused by continued intense competition; |
• | Higher interest expense primarily related to financing activities associated with our capital investments; and |
• | Higher income tax expense primarily due to higher year-over-year income as impacted by fluctuations in derivative mark-to-market valuations in our Canadian operations. |
Three Months Ended March 31, | |||||||
2017 | 2016 | ||||||
Acquisition capital (1) (2) | $ | 1,258 | $ | 85 | |||
Expansion capital (1) (3) | 307 | 370 | |||||
Maintenance capital (3) | 59 | 47 | |||||
$ | 1,624 | $ | 502 |
(1) | Acquisition capital for the first three months of 2017 primarily relates to the ACC Acquisition. See Note 6 to our Condensed Consolidated Financial Statements for further discussion regarding our acquisition activities. |
(2) | Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.” Subsequent contributions to unconsolidated entities related to expansion projects of such entities are recognized in “Expansion capital.” We account for our investments in such entities under the equity method of accounting. |
(3) | Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. Capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital. |
Projects | 2017 | |
Diamond Pipeline | $300 | |
Permian Basin Area Systems | 150 | |
Fort Saskatchewan Facility Projects | 90 | |
STACK Projects | 50 | |
Cushing Terminal Expansions | 30 | |
St. James Terminal Projects | 20 | |
Other Projects | 260 | |
Total Projected 2017 Expansion Capital Expenditures | $900 |
Three Months Ended March 31, | Variance | ||||||||||||||
2017 | 2016 | $ | % | ||||||||||||
Transportation segment adjusted EBITDA (1) | $ | 273 | $ | 281 | $ | (8 | ) | (3 | )% | ||||||
Facilities segment adjusted EBITDA (1) | 188 | 167 | 21 | 13 | % | ||||||||||
Supply and Logistics segment adjusted EBITDA (1) | 51 | 184 | (133 | ) | (72 | )% | |||||||||
Adjustments: | |||||||||||||||
Depreciation and amortization of unconsolidated entities | (14 | ) | (12 | ) | (2 | ) | (17 | )% | |||||||
Selected items impacting comparability - segment adjusted EBITDA | 267 | (177 | ) | 444 | ** | ||||||||||
Unallocated general and administrative expenses | (1 | ) | (1 | ) | — | — | % | ||||||||
Depreciation and amortization | (122 | ) | (114 | ) | (8 | ) | (7 | )% | |||||||
Interest expense, net | (129 | ) | (116 | ) | (13 | ) | (11 | )% | |||||||
Other income/(expense), net | (5 | ) | 5 | (10 | ) | ** | |||||||||
Income tax expense | (106 | ) | (40 | ) | (66 | ) | (165 | )% | |||||||
Net income | 402 | 177 | 225 | 127 | % | ||||||||||
Net income attributable to noncontrolling interests | (361 | ) | (141 | ) | (220 | ) | (156 | )% | |||||||
Net income attributable to PAGP | $ | 41 | $ | 36 | $ | 5 | 14 | % | |||||||
Basic net income per Class A share (2) | $ | 0.34 | $ | 0.39 | $ | (0.05 | ) | (13 | )% | ||||||
Diluted net income per Class A share (2) | $ | 0.34 | $ | 0.37 | $ | (0.03 | ) | (8 | )% | ||||||
Basic weighted average Class A shares outstanding (2) | 120 | 95 | 25 | 26 | % | ||||||||||
Diluted weighted average Class A shares outstanding (2) | 120 | 245 | (125 | ) | (51 | )% |
** | Indicates that variance as a percentage is not meaningful. |
(1) | Segment adjusted EBITDA is the measure of segment performance that is utilized by our Chief Operating Decision Maker (“CODM”) to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See Note 13 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments. |
(2) | The share and per-share amounts for the 2016 period have been retroactively adjusted to reflect the effect of the reverse split that was effected as part of the Simplification Transactions. See Note 1 to our Condensed Consolidated Financial Statements for additional discussion of the Simplification Transactions. |
Three Months Ended March 31, | Variance | ||||||||||||||
2017 | 2016 | $ | % | ||||||||||||
Net income | $ | 402 | $ | 177 | $ | 225 | 127 | % | |||||||
Add/(Subtract): | |||||||||||||||
Interest expense, net | 129 | 116 | 13 | 11 | % | ||||||||||
Income tax expense | 106 | 40 | 66 | 165 | % | ||||||||||
Depreciation and amortization | 122 | 114 | 8 | 7 | % | ||||||||||
Depreciation and amortization of unconsolidated entities (1) | 14 | 12 | 2 | 17 | % | ||||||||||
Selected Items Impacting Comparability - Adjusted EBITDA: | |||||||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments (2) | (289 | ) | 122 | (411 | ) | ** | |||||||||
Long-term inventory costing adjustments (3) | 7 | 23 | (16 | ) | ** | ||||||||||
Deficiencies under minimum volume commitments, net (4) | 11 | 27 | (16 | ) | (59 | )% | |||||||||
Equity-indexed compensation expense (5) | 3 | 4 | (1 | ) | ** | ||||||||||
Net (gain)/loss on foreign currency revaluation (6) | (4 | ) | 1 | (5 | ) | ** | |||||||||
Significant acquisition-related expenses (7) | 5 | — | 5 | ** | |||||||||||
Selected Items Impacting Comparability - segment adjusted EBITDA | (267 | ) | 177 | (444 | ) | ** | |||||||||
Losses from derivative activities (2) | 4 | — | 4 | ** | |||||||||||
Net (gain)/loss on foreign currency revaluation (6) | 1 | (4 | ) | 5 | ** | ||||||||||
Selected Items Impacting Comparability - Adjusted EBITDA (8) | $ | (262 | ) | $ | 173 | $ | (435 | ) | ** | ||||||
Adjusted EBITDA (8) | $ | 511 | $ | 632 | $ | (121 | ) | (19 | )% |
(1) | Over the past several years, we have increased our participation in pipeline strategic joint ventures, which are accounted for under the equity method of accounting. Our proportionate share of the depreciation and amortization expense associated with such unconsolidated entities is excluded when reviewing Adjusted EBITDA, similar to our consolidated pipelines. |
(2) | 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 of operations, 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 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, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option. See Note 10 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities and our Preferred Distribution Rate Reset Option. |
(3) | 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 treat 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 as a selected item impacting comparability. See Note 4 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional inventory disclosures. |
(4) | 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. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors 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. |
(5) | Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in PAA common units and awards that will or may be settled in cash. The awards that will or may be settled in PAA common units are included in PAA's diluted net income per unit calculation when the applicable performance criteria have been met. The compensation expense associated with these awards is considered as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in PAA's diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in PAA common units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans. |
(6) | During the periods presented, there were fluctuations in the value of CAD to USD, resulting in gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability. See Note 10 to our Condensed Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities. |
(7) | Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 to our Condensed Consolidated Financial Statements for additional discussion. |
(8) | Adjusted EBITDA includes Other income/expense, net adjusted for selected items impacting comparability. Segment adjusted EBITDA is exclusive of such amounts. |
Operating Results (1) | Three Months Ended March 31, | Favorable/(Unfavorable) Variance | ||||||||||||||
(in millions, except per barrel data) | 2017 | 2016 | $ | % | ||||||||||||
Revenues | ||||||||||||||||
Tariff activities | $ | 352 | $ | 349 | $ | 3 | 1 | % | ||||||||
Trucking | 37 | 34 | 3 | 9 | % | |||||||||||
Total transportation revenues | 389 | 383 | 6 | 2 | % | |||||||||||
Costs and expenses | ||||||||||||||||
Trucking costs | (24 | ) | (21 | ) | (3 | ) | (14 | )% | ||||||||
Field operating costs (2) | (137 | ) | (137 | ) | — | — | % | |||||||||
Equity-indexed compensation expense - field operating costs | (4 | ) | — | (4 | ) | ** | ||||||||||
Segment general and administrative expenses (2) (3) | (27 | ) | (23 | ) | (4 | ) | (17 | )% | ||||||||
Equity-indexed compensation expense - general and administrative | (2 | ) | (2 | ) | — | ** | ||||||||||
Equity earnings in unconsolidated entities | 53 | 47 | 6 | 13 | % | |||||||||||
Adjustments (4): | ||||||||||||||||
Depreciation and amortization of unconsolidated entities | 14 | 12 | 2 | 17 | % | |||||||||||
Deficiencies under minimum volume commitments, net | 5 | 20 | (15 | ) | (75 | )% | ||||||||||
Equity-indexed compensation expense | 1 | 2 | (1 | ) | ** | |||||||||||
Significant acquisition-related expenses | 5 | — | 5 | ** | ||||||||||||
Segment adjusted EBITDA | $ | 273 | $ | 281 | $ | (8 | ) | (3 | )% | |||||||
Maintenance capital | $ | 29 | $ | 35 | $ | 6 | 17 | % | ||||||||
Segment adjusted EBITDA per barrel | $ | 0.64 | $ | 0.67 | $ | (0.03 | ) | (4 | )% | |||||||
Average Daily Volumes | Three Months Ended March 31, | Favorable/(Unfavorable) Variance | ||||||||||||||
(in thousands of barrels per day) (5) | 2017 | 2016 | Volumes | % | ||||||||||||
Tariff activities volumes | ||||||||||||||||
Crude oil pipelines (by region): | ||||||||||||||||
Permian Basin (6) | 2,466 | 2,045 | 421 | 21 | % | |||||||||||
South Texas / Eagle Ford (6) | 310 | 313 | (3 | ) | (1 | )% | ||||||||||
Western | 189 | 175 | 14 | 8 | % | |||||||||||
Rocky Mountain (6) | 385 | 437 | (52 | ) | (12 | )% | ||||||||||
Gulf Coast | 342 | 581 | (239 | ) | (41 | )% | ||||||||||
Central (6) | 405 | 379 | 26 | 7 | % | |||||||||||
Canada | 363 | 394 | (31 | ) | (8 | )% | ||||||||||
Crude oil pipelines | 4,460 | 4,324 | 136 | 3 | % | |||||||||||
NGL pipelines | 180 | 178 | 2 | 1 | % | |||||||||||
Tariff activities total volumes | 4,640 | 4,502 | 138 | 3 | % | |||||||||||
Trucking volumes | 114 | 106 | 8 | 8 | % | |||||||||||
Transportation segment total volumes | 4,754 | 4,608 | 146 | 3 | % |
(2) | Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above. |
(3) | Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. |
(4) | Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 13 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments. |
(5) | Average daily volumes are calculated as the total volumes (attributable to our interest) for the period divided by the number of days in the period. |
Favorable/(Unfavorable) Variance Three Months Ended March 31, 2017-2016 | ||||||||
(in millions) | Revenues | Equity Earnings | ||||||
Tariff activities: | ||||||||
Permian Basin region | $ | 25 | $ | 1 | ||||
Rocky Mountain region | (8 | ) | 2 | |||||
Gulf Coast region | (11 | ) | — | |||||
Other (including pipeline loss allowance revenue) | (3 | ) | 3 | |||||
Total tariff activities variance | $ | 3 | $ | 6 |
• | Permian Basin region — The increase in revenues was largely driven by (i) increased production in the Delaware Basin, which favorably impacted our Basin pipeline, (ii) higher volumes on our Cactus pipeline and (iii) results from the Alpha Crude Connector gathering system, which we acquired in February 2017. |
• | Rocky Mountain region — The decrease in revenues was largely driven by (i) lower volumes due to downtime on our Wahsatch pipeline, which we proactively shut down for approximately 30 days during the first quarter of 2017 as a precautionary measure in response to indications of soil movement identified by our monitoring systems, and (ii) the sale of 50% of our investment in Cheyenne Pipeline in June 2016, subsequent to which it was accounted for under the equity method of accounting. |
• | Gulf Coast region — Revenues and volumes decreased primarily due to the sale of certain of our Gulf Coast pipelines in March 2016 and July 2016. |
Three Months Ended March 31, | Favorable/ (Unfavorable) Variance | ||||||||||||
Operating Segment | 2017 | 2016 | |||||||||||
Transportation | $ | 6 | $ | 2 | $ | (4 | ) | ||||||
Facilities | 3 | 1 | (2 | ) | |||||||||
Supply and Logistics | 3 | 1 | (2 | ) | |||||||||
$ | 12 | $ | 4 | $ | (8 | ) |
Operating Results (1) | Three Months Ended March 31, | Favorable/(Unfavorable)Variance | ||||||||||||||
(in millions, except per barrel data) | 2017 | 2016 | $ | % | ||||||||||||
Revenues | $ | 293 | $ | 265 | $ | 28 | 11 | % | ||||||||
Natural gas related costs | (11 | ) | (5 | ) | (6 | ) | (120 | )% | ||||||||
Field operating costs (2) | (82 | ) | (85 | ) | 3 | 4 | % | |||||||||
Equity-indexed compensation expense - field operating costs | (1 | ) | — | (1 | ) | ** | ||||||||||
Segment general and administrative expenses (2) (3) | (17 | ) | (15 | ) | (2 | ) | (13 | )% | ||||||||
Equity-indexed compensation expense - general and administrative | (2 | ) | (1 | ) | (1 | ) | ** | |||||||||
Adjustments (4): | ||||||||||||||||
Deficiencies under minimum volume commitments, net | 6 | 7 | (1 | ) | (14 | )% | ||||||||||
Losses from derivative activities net of inventory valuation adjustments | 2 | — | 2 | ** | ||||||||||||
Equity-indexed compensation expense | — | 1 | (1 | ) | ** | |||||||||||
Segment adjusted EBITDA | $ | 188 | $ | 167 | $ | 21 | 13 | % | ||||||||
Maintenance capital | $ | 27 | $ | 9 | $ | (18 | ) | (200 | )% | |||||||
Segment adjusted EBITDA per barrel | $ | 0.47 | $ | 0.44 | $ | 0.03 | 7 | % | ||||||||
Three Months Ended March 31, | Favorable/(Unfavorable)Variance | |||||||||||||||
Volumes (5) | 2017 | 2016 | Volumes | % | ||||||||||||
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels) | 111 | 105 | 6 | 6 | % | |||||||||||
Rail load / unload volumes (average volumes in thousands of barrels per day) | 35 | 91 | (56 | ) | (62 | )% | ||||||||||
Natural gas storage (average monthly working capacity in billions of cubic feet) | 97 | 97 | — | — | % | |||||||||||
NGL fractionation (average volumes in thousands of barrels per day) | 125 | 115 | 10 | 9 | % | |||||||||||
Facilities segment total volumes (average monthly volumes in millions of barrels) (6) | 132 | 127 | 5 | 4 | % |
(2) | Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above. |
(3) | Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. |
(4) | Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 13 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments. |
(5) | Average monthly volumes are calculated as total volumes for the period divided by the number of months in the period. |
(6) | Facilities segment total volumes is calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and |
• | NGL Storage, NGL Fractionation and Canadian Natural Gas Processing — Revenues increased by $33 million primarily due to contributions from the Western Canada NGL assets we acquired in August 2016 and also from higher fees at certain of our NGL storage and fractionation facilities, which were largely offset in our Supply and Logistics segment results. |
• | Rail Terminals — Revenues decreased by $8 million primarily due to lower volumes at our U.S. terminals resulting from less favorable market conditions, partially offset by revenues and volumes from our Fort Saskatchewan rail terminal that came on line in April 2016. |
• | Crude Oil Storage — Revenues decreased by $3 million primarily due to (i) lower results related to the sale of certain of our East Coast terminals in April 2016 and (ii) decreased utilization at certain of our West Coast terminals. Such decreases were partially offset by increased revenues from our St. James and Cushing terminals due to aggregate capacity expansions of over 2.5 million barrels and higher ancillary fees. |
Operating Results (1) | Three Months Ended March 31, | Favorable/(Unfavorable)Variance | ||||||||||||||
(in millions, except per barrel data) | 2017 | 2016 | $ | % | ||||||||||||
Revenues | $ | 6,400 | $ | 3,821 | $ | 2,579 | 67 | % | ||||||||
Purchases and related costs | (5,970 | ) | (3,677 | ) | (2,293 | ) | (62 | )% | ||||||||
Field operating costs (2) | (67 | ) | (81 | ) | 14 | 17 | % | |||||||||
Equity-indexed compensation expense - field operating costs | — | — | — | ** | ||||||||||||
Segment general and administrative expenses (2) (3) | (23 | ) | (25 | ) | 2 | 8 | % | |||||||||
Equity-indexed compensation expense - general and administrative | (3 | ) | (1 | ) | (2 | ) | ** | |||||||||
Adjustments (4): | ||||||||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments | (291 | ) | 122 | (413 | ) | ** | ||||||||||
Long-term inventory costing adjustments | 7 | 23 | (16 | ) | ** | |||||||||||
Net (gain)/loss on foreign currency revaluation | (4 | ) | 1 | (5 | ) | ** | ||||||||||
Equity-indexed compensation expense | 2 | 1 | 1 | ** | ||||||||||||
Segment adjusted EBITDA | $ | 51 | $ | 184 | $ | (133 | ) | (72 | )% | |||||||
Maintenance capital | $ | 3 | $ | 3 | $ | — | — | % | ||||||||
Segment adjusted EBITDA per barrel | $ | 0.45 | $ | 1.65 | $ | (1.20 | ) | (73 | )% | |||||||
Average Daily Volumes | Three Months Ended March 31, | Favorable/(Unfavorable)Variance | ||||||||||||||
(in thousands of barrels per day) | 2017 | 2016 | Volumes | % | ||||||||||||
Crude oil lease gathering purchases | 916 | 913 | 3 | — | % | |||||||||||
NGL sales | 351 | 308 | 43 | 14 | % | |||||||||||
Waterborne cargos | 7 | 7 | — | — | % | |||||||||||
Supply and Logistics segment total | 1,274 | 1,228 | 46 | 4 | % |
(2) | Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above. |
(3) | Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. |
(4) | Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 13 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments. |
NYMEX WTI Crude Oil Price | |||||||
Low | High | ||||||
Three months ended March 31, 2017 | $ | 47 | $ | 54 | |||
Three months ended March 31, 2016 | $ | 26 | $ | 41 |
• | Impact from Certain Derivative Activities Net of Inventory Valuation Adjustments — The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period) and inventory valuation adjustments, as applicable. See Note 10 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from segment adjusted EBITDA and thus are reflected as an “Adjustment” in the table above. |
• | Crude Oil Operations — Net revenues from our crude oil supply and logistics activities decreased for the three months ended March 31, 2017 as compared to the same 2016 period, primarily due to continued and intensifying competition, largely due to overbuilt infrastructure underwritten with volume commitments and the effect of such on differentials, as well as volume declines in certain areas, which negatively impacted our unit margins. See the “Outlook” section below for additional discussion of recent market conditions. |
• | NGL Operations — Net revenues from our NGL operations decreased for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016, largely due to (i) higher supply costs driven by competition, which more than offset higher sales volume from the Western Canada NGL assets acquired in August 2016, (ii) warmer weather during the 2016-2017 heating season and (iii) higher storage and processing fees for the 2017 period, which were largely offset in our Facilities segment results. |
• | Long-Term Inventory Costing Adjustments — Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was 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. These costing adjustments impact our net revenues but are excluded from segment adjusted EBITDA and thus are reflected as an “Adjustment” in the table above. |
• | Foreign Exchange Impacts — Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. In addition, the appreciation of CAD relative to USD resulted in higher net USD costs of approximately $4 million for the three months ended March 31, 2017 compared to the same period in 2016. Such costs are primarily associated with intercompany facility fees and are largely offset in our Facilities segment results. |
As of March 31, 2017 | |||
Availability under PAA senior unsecured revolving credit facility (1) (2) | $ | 1,582 | |
Availability under PAA senior secured hedged inventory facility (1) (2) | 1,091 | ||
Availability under PAA senior unsecured 364-day revolving credit facility | 1,000 | ||
Amounts outstanding under PAA commercial paper program | (958 | ) | |
Subtotal | 2,715 | ||
Cash and cash equivalents | 41 | ||
Total | $ | 2,756 |
(1) | Represents availability prior to giving effect to amounts outstanding under the PAA commercial paper program, which reduce available capacity under the facilities. |
(2) | Available capacity was reduced by outstanding letters of credit of $77 million, comprised of $18 million under the PAA senior unsecured revolving credit facility and $59 million under the PAA senior secured hedged inventory facility. |
Type of Offering | Class A Shares Issued | Net Proceeds (1) | ||||||
Continuous Offering Program | 1,786,326 | $ | 61 | (2) (3) | ||||
Underwritten Offering | 48,300,000 | 1,474 | (3) | |||||
50,086,326 | $ | 1,535 |
(2) | We pay commissions to our sales agents in connection with issuances of Class A shares under our Continuous Offering Program. We paid $1 million of such commissions during the three months ended March 31, 2017. |
(3) | Pursuant to the Omnibus Agreement entered into in conjunction with the Simplification Transactions, we used the net proceeds from the sale of our Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA. See "—Subsidiary Sales of Common Units" below. |
Remainder of 2017 | 2018 | 2019 | 2020 | 2021 | 2022 and Thereafter | Total | |||||||||||||||||||||
Long-term debt, including current maturities and related interest payments (1) | $ | 360 | $ | 1,054 | $ | 1,270 | $ | 870 | $ | 940 | $ | 11,054 | $ | 15,548 | |||||||||||||
Leases and rights-of-way easements (2) | 143 | 167 | 142 | 119 | 98 | 447 | 1,116 | ||||||||||||||||||||
Other obligations (3) | 482 | 209 | 155 | 131 | 128 | 436 | 1,541 | ||||||||||||||||||||
Subtotal | 985 | 1,430 | 1,567 | 1,120 | 1,166 | 11,937 | 18,205 | ||||||||||||||||||||
Crude oil, natural gas, NGL and other purchases (4) | 4,626 | 2,992 | 2,395 | 1,653 | 1,460 | 4,832 | 17,958 | ||||||||||||||||||||
Total | $ | 5,611 | $ | 4,422 | $ | 3,962 | $ | 2,773 | $ | 2,626 | $ | 16,769 | $ | 36,163 |
(1) | Includes debt service payments, interest payments due on PAA’s senior notes, the commitment fee on assumed available capacity under the PAA credit facilities. Although there may be short-term borrowings under the PAA credit facilities and the PAA commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the PAA credit facilities or the PAA commercial paper program) in the amounts above. |
(2) | Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars. Includes capital and operating leases as defined by FASB guidance, as well as obligations for rights-of-way easements. |
(3) | Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) non-cancelable commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity method investments. The transportation agreements include approximately $830 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. |
(4) | Amounts are primarily based on estimated volumes and market prices based on average activity during March 2017. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control. |
• | our ability to pay distributions to our Class A shareholders; |
• | our expected receipt of, and amounts of, distributions from Plains AAP, L.P.; |
• | declines in the volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors; |
• | the effects of competition; |
• | market distortions caused by producer over-commitments to new or recently constructed infrastructure projects, which impacts volumes, margins, returns and overall earnings; |
• | unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof); |
• | environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; |
• | maintenance of PAA's credit rating and ability to receive open credit from suppliers and trade counterparties; |
• | fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements; |
• | the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including attacks on our electronic and computer systems; |
• | failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors; |
• | tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; |
• | the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from historical operations; |
• | the currency exchange rate of the Canadian dollar; |
• | continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business; |
• | inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; |
• | non-utilization of our assets and facilities; |
• | increased costs, or lack of availability, of insurance; |
• | weather interference with business operations or project construction, including the impact of extreme weather events or conditions; |
• | the availability of, and our ability to consummate, acquisition or combination opportunities; |
• | the effectiveness of our risk management activities; |
• | shortages or cost increases of supplies, materials or labor; |
• | the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations; |
• | fluctuations in the debt and equity markets, including the price of PAA's units at the time of vesting under its long-term incentive plans; |
• | risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; |
• | factors affecting demand for natural gas and natural gas storage services and rates; |
• | general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and |
• | other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids. |
• | Crude oil |
• | Natural gas |
• | NGL and other |
Fair Value | Effect of 10% Price Increase | Effect of 10% Price Decrease | |||||||||
Crude oil | $ | 4 | $ | (84 | ) | $ | 85 | ||||
Natural gas | (7 | ) | $ | 11 | $ | (11 | ) | ||||
NGL and other | (3 | ) | $ | (43 | ) | $ | 43 | ||||
Total fair value | $ | (6 | ) |
PLAINS GP HOLDINGS, L.P. | ||
By: | PAA GP HOLDINGS LLC, | |
its general partner | ||
By: | /s/ Greg L. Armstrong | |
Greg L. Armstrong, | ||
Chairman of the Board, Chief Executive Officer and Director of PAA GP Holdings LLC (Principal Executive Officer) | ||
May 9, 2017 | ||
By: | /s/ Al Swanson | |
Al Swanson, | ||
Executive Vice President and Chief Financial Officer of PAA GP Holdings LLC (Principal Financial Officer) | ||
May 9, 2017 | ||
By: | /s/ Chris Herbold | |
Chris Herbold, | ||
Vice President—Accounting and Chief Accounting Officer of PAA GP Holdings LLC (Principal Accounting Officer) | ||
May 9, 2017 |
2.1 * | — | Securities Purchase Agreement dated as of January 19, 2017 by and between COG Operating LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to PAA's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). |
2.2 * | — | Securities Purchase Agreement dated as of January 19, 2017 by and between Frontier Midstream Solutions, LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.2 to PAA's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017). |
3.1 | — | Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013). |
3.2 | — | Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K filed November 21, 2016). |
3.3 | — | Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013). |
3.4 | — | Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated as of February 16, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed February 21, 2017). |
3.5 | — | Sixth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.5 to our Current Report on Form 8-K filed November 21, 2016). |
3.6 | — | Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016). |
3.7 | — | Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016). |
3.8 | — | Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to PAA’s Current Report on Form 8-K filed January 4, 2008). |
4.1 | — | Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002). |
4.2 | — | Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed May 12, 2006). |
4.3 | — | Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to PAA’s Current Report on Form 8-K filed October 30, 2006). |
4.4 | — | Thirteenth Supplemental Indenture (Series A and Series B 6.50% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed April 23, 2008). |
4.5 | — | Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed April 20, 2009). |
4.6 | — | Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed September 4, 2009). |
4.7 | — | Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed January 11, 2011). |
4.8 | — | Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed March 26, 2012). |
4.9 | — | Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed March 26, 2012). |
4.10 | — | Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed December 12, 2012). |
4.11 | — | Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed December 12, 2012). |
4.12 | — | Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 15, 2013). |
4.13 | — | Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014). |
4.14 | — | Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014). |
4.15 | — | Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 11, 2014). |
4.16 | — | Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014). |
4.17 | — | Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 26, 2015). |
4.18 | Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed November 29, 2016). | |
4.19 | — | Shareholder and Registration Rights Agreement dated October 21, 2013 by and among Plains GP Holdings, L.P. and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed October 25, 2013). |
10.1 **† | — | Form of Director LTIP Grant Letter (February 2017) - Director Grant - Designated Directors and Audit Committee Members (PAGP Plan) |
10.2 **† | — | Form of Director LTIP Grant Letter (February 2017) - Audit Committee Supplement (PAGP Plan) |
10.3 **† | — | Form of Director LTIP Grant Letter (February 2017) - Independent Director Grant (PAGP Plan) |
31.1 † | — | Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a). |
31.2 † | — | Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a). |
32.1 †† | — | Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350. |
32.2 †† | — | Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350. |
101.INS† | — | XBRL Instance Document |
101.SCH† | — | XBRL Taxonomy Extension Schema Document |
101.CAL† | — | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF† | — | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB† | — | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE† | — | XBRL Taxonomy Extension Presentation Linkbase Document |
Re: | Grant of Phantom Class A Shares |
1. | Subject to the further provisions of this Agreement, your Phantom Class A Shares shall vest (become payable in the form of one Class A Share of PAGP for each Phantom Class A Share) in equal 25% increments (2,500 Phantom Class A Shares per year) annually on the August Distribution Date. |
2. | Subject to the further provisions of this Agreement, your DERs shall be payable in cash substantially contemporaneously with each Distribution Date. |
3. | As of each vesting date, for so long as your service on the Board of Directors has not been terminated, you shall be deemed to have automatically received a grant, evidenced hereby, of 2,500 additional Phantom Class A Shares (and tandem DERs), such that the total outstanding Phantom Class A Shares (and tandem DERs) granted by this letter shall remain 10,000. |
4. | Immediately after the vesting of any Phantom Class A Shares, an equal number of DERs shall expire. |
5. | Upon any forfeiture of Phantom Class A Shares, an equal number of DERs shall expire. |
6. | In the event that (i) you voluntarily terminate your service on the Board of Directors (other than for Retirement) or (ii) your service on the Board of Directors is terminated by the Board (by a majority vote of the remaining Directors) for Cause (as defined in the LLC Agreement), all unvested Phantom Class A Shares (and tandem DERs) shall be forfeited as of the date service terminates. |
7. | In the event your service on the Board of Directors is terminated (i) because of your death or disability (as determined in good faith by the Board), (ii) due to your Retirement, or (iii) for any reason other than as described in clauses (i) and (ii) of paragraph 6 above, all unvested Phantom Class A Shares (and any tandem DERs) shall immediately become nonforfeitable, and shall vest (or, in the case of DERs, be paid) in full as of the next following Distribution Date. Upon such payment, the tandem DERs associated with the Phantom Class A Shares that are vesting shall expire. |
8. | In the event of a vesting under paragraph 7 above, the provisions of paragraph 3 above shall no longer be operative. |
9. | For the avoidance of doubt, to the extent the expiration of a DER relates to the vesting of a Phantom Class A Share on a Distribution Date, the intent is for the DER to be paid with respect to such Distribution Date before the DER expires. |
By: | ____________________________________ |
Name: | Richard McGee |
Title: | Executive Vice President |
Primary Beneficiary Name | Relationship | Percent (Must total 100%) |
Secondary Beneficiary Name | Relationship | Percent (Must total 100%) |
Re: | Grant of Phantom Class A Shares |
1. | Subject to the further provisions of this Agreement, your Phantom Class A Shares shall vest (become payable in the form of one Class A Share of PAGP for each Phantom Class A Share) in equal 25% increments (2,500 Phantom Class A Shares per year) annually on the August Distribution Date. |
2. | Subject to the further provisions of this Agreement, your DERs shall be payable in cash substantially contemporaneously with each Distribution Date. |
3. | As of each vesting date, for so long as you serve on the Audit Committee of the Board of Directors (the “Audit Committee”), you shall be deemed to have automatically received a grant, evidenced hereby, of 2,500 additional Phantom Class A Shares (and tandem DERs), such that the total outstanding Phantom Class A Shares (and tandem DERs) granted by this letter shall remain 10,000. |
4. | Immediately after the vesting of any Phantom Class A Shares, an equal number of DERs shall expire. |
5. | Upon any forfeiture of Phantom Class A Shares, an equal number of DERs shall expire. |
6. | In the event that (i) you voluntarily terminate your service on the Audit Committee (other than for Retirement) or (ii) your service on the Board of Directors is terminated by the Board (by a majority vote of the remaining Directors) for Cause (as defined in the LLC Agreement), all unvested Phantom Class A Shares (and tandem DERs) shall be forfeited as of the date service terminates. |
7. | In the event your service on the Audit Committee is terminated (i) because of your death or disability (as determined in good faith by the Board), (ii) due to your Retirement, or (iii) for any reason other than as described in clauses (i) and (ii) of paragraph 6 above, all unvested Phantom Class A Shares (and any tandem DERs) shall immediately become nonforfeitable, and shall vest (or, in the case of DERs, be paid) in full as of the next following Distribution Date. Upon such payment, the tandem DERs associated with the Phantom Class A Shares that are vesting shall expire. |
8. | In the event of a vesting under paragraph 7 above, the provisions of paragraph 3 above shall no longer be operative. |
9. | For the avoidance of doubt, to the extent the expiration of a DER relates to the vesting of a Phantom Class A Share on a Distribution Date, the intent is for the DER to be paid with respect to such Distribution Date before the DER expires. |
By: | ____________________________________ |
Name: | Richard McGee |
Title: | Executive Vice President |
Primary Beneficiary Name | Relationship | Percent (Must total 100%) |
Secondary Beneficiary Name | Relationship | Percent (Must total 100%) |
Re: | Grant of Phantom Class A Shares |
1. | Subject to the further provisions of this Agreement, your Phantom Class A Shares shall vest (become payable in the form of one Class A Share of PAGP for each Phantom Class A Share) in equal 25% increments (3,750 Phantom Class A Shares per year) annually on the August Distribution Date. |
2. | Subject to the further provisions of this Agreement, your DERs shall be payable in cash substantially contemporaneously with each Distribution Date. |
3. | As of each vesting date, for so long as you qualify as an Independent Director (as such term is defined in the LLC Agreement), you shall be deemed to have automatically received a grant, evidenced hereby, of 3,750 additional Phantom Class A Shares (and tandem DERs), such that the total outstanding Phantom Class A Shares (and tandem DERs) granted by this letter shall remain 15,000. |
4. | Immediately after the vesting of any Phantom Class A Shares, an equal number of DERs shall expire. |
5. | Upon any forfeiture of Phantom Class A Shares, an equal number of DERs shall expire. |
6. | In the event that (i) you voluntarily terminate your service on the Board of Directors (other than for Retirement), (ii) your service on the Board of Directors is terminated by the Board (by a majority vote of the remaining Directors) for Cause (as defined in the LLC Agreement), or (iii) you no longer qualify as an Independent Director, all unvested Phantom Class A Shares (and tandem DERs) shall be forfeited as of the date service terminates. |
7. | In the event your service on the Board of Directors is terminated (i) because of your death or disability (as determined in good faith by the Board), (ii) due to your Retirement, or (iii) for any reason other than as described in clauses (i), (ii) and (iii) of paragraph 6 above, all unvested Phantom Class A Shares (and any tandem DERs) shall immediately become nonforfeitable, and shall vest (or, in the case of DERs, be paid) in full as of the next following Distribution Date. Upon such payment, the tandem DERs associated with the Phantom Class A Shares that are vesting shall expire. |
8. | In the event of a vesting under paragraph 7 above, the provisions of paragraph 3 above shall no longer be operative. |
9. | For the avoidance of doubt, to the extent the expiration of a DER relates to the vesting of a Phantom Class A Share on a Distribution Date, the intent is for the DER to be paid with respect to such Distribution Date before the DER expires. |
By: | ____________________________________ |
Name: | Richard McGee |
Title: | Executive Vice President |
Primary Beneficiary Name | Relationship | Percent (Must total 100%) |
Secondary Beneficiary Name | Relationship | Percent (Must total 100%) |
/s/ Greg L. Armstrong |
Greg L. Armstrong |
Chief Executive Officer |
/s/ Al Swanson |
Al Swanson |
Chief Financial Officer |
/s/ Greg L. Armstrong |
Name: Greg L. Armstrong |
Date: May 9, 2017 |
/s/ Al Swanson |
Name: Al Swanson |
Date: May 9, 2017 |
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Document and Entity Information - shares |
3 Months Ended | |
---|---|---|
Mar. 31, 2017 |
May 01, 2017 |
|
Document and Entity Information | ||
Entity Registrant Name | PLAINS GP HOLDINGS LP | |
Entity Central Index Key | 0001581990 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2017 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding (shares) | 152,280,208 | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | Q1 |
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares |
Mar. 31, 2017 |
Dec. 31, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
---|---|---|---|---|
Class A Shares | ||||
Shares outstanding | ||||
Shares outstanding (shares) | 151,779,960 | 101,206,526 | 100,172,660 | 86,099,037 |
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2017 |
Mar. 31, 2016 |
|
Income Statement [Abstract] | ||
Interest expense, capitalized interest | $ 6 | $ 13 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2017 |
Mar. 31, 2016 |
|
Statement of Comprehensive Income [Abstract] | ||
Net income | $ 402 | $ 177 |
Other comprehensive income | 36 | 118 |
Comprehensive income | 438 | 295 |
Comprehensive income attributable to noncontrolling interests | (392) | (258) |
Comprehensive income attributable to PAGP | $ 46 | $ 37 |
Organization and Basis of Consolidation and Presentation |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization and Basis of Consolidation and Presentation | Organization and Basis of Consolidation and Presentation Organization Plains 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 December 31, 2016, 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 March 31, 2017, our sole assets consisted of (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”) that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 53% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately 150.8 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 holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of March 31, 2017, directly owned an approximate 37% limited partner interest in PAA represented by approximately 288.3 million PAA common units. 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 for crude oil, natural gas liquids (“NGL”), natural gas and refined products. 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 13 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 (“PMC”). References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries. Simplification Transactions On November 15, 2016, the Plains Entities closed a series of transactions and executed several organizational and ancillary documents (the “Simplification Transactions”) that simplified our governance structure and permanently eliminated PAA's incentive distribution rights (“IDRs”) and the economic rights associated with its 2% general partner interest in exchange for the issuance by PAA to AAP of common units and the assumption by PAA of all of AAP’s outstanding debt. As part of the Simplification Transactions, we effected a reverse split of our Class A and Class B shares, in each case, at a ratio of approximately 1-for-2.663. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented in this Form 10-Q. See Note 1 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional discussion of the Simplification Transactions. Definitions Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:
Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2016 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of 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. The condensed consolidated balance sheet data as of December 31, 2016 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2017 should not be taken as indicative of results to be expected for the entire year. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. |
Recent Accounting Pronouncements |
3 Months Ended |
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Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Except as discussed below and in our 2016 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2017 that are of significance or potential significance to us. Accounting Standards Updates Adopted During the Period In March 2016, the FASB issued ASU 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplified several aspects of the accounting for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance was effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted the applicable provisions of the ASU on January 1, 2017 and (i) elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption, and (ii) will classify units directly withheld for tax-withholding purposes as a financing activity on our Condensed Consolidated Statement of Cash Flows for all periods presented. Our adoption did not have a material impact on our financial position, results of operations or cash flows for the periods presented. In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. The amendments within this ASU eliminate Step 2 from the goodwill impairment test, which currently requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Under the amended standard, goodwill impairment will instead be measured using Step 1 of the goodwill impairment test with goodwill impairment being equal to the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods, with early adoption permitted. We early adopted this ASU in the first quarter of 2017, and the amendments therein will be applied prospectively to all future goodwill impairment tests performed on an interim or annual basis. Accounting Standards Updates Issued During the Period In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which improves the guidance for determining whether a transaction involves the purchase or disposal of a business or an asset. This guidance becomes effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We plan to adopt this guidance on January 1, 2018 and will apply the new guidance to applicable transactions occurring after that date. In February 2017, the FASB issued ASU 2017-05, Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update includes the following clarifications: (i) nonfinancial assets within the scope of Subtopic 610-20 may include nonfinancial assets transferred within a legal entity to a counterparty, (ii) an entity should allocate consideration to each distinct asset by applying the guidance in Topic 606 on allocating the transaction price to performance obligations and (iii) requires entities to derecognize a distinct nonfinancial asset or distinct in substance nonfinancial asset in a partial sale transaction when it (1) does not have (or ceases to have) a controlling financial interest in the legal entity that holds the asset in accordance with Subtopic 810-10 and (2) transfers control of the asset in accordance with Topic 606. This guidance is effective beginning after December 15, 2017, including interim periods within those periods and must be adopted at the same time as ASC 606. We will adopt this guidance on January 1, 2018 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows. |
Net Income Per Class A Share |
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Mar. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B 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 9 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. For the three months ended March 31, 2017, the possible exchange of any AAP units and certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share. For the three months ended March 31, 2016, the possible exchange of any AAP units and certain AAP Management Units would have had a dilutive effect on basic net income per Class A share. For the three months ended March 31, 2017 and 2016, 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):
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Accounts Receivable, Net |
3 Months Ended |
---|---|
Mar. 31, 2017 | |
Receivables [Abstract] | |
Accounts Receivable, Net | Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of March 31, 2017 and December 31, 2016, we had received $81 million and $89 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $46 million and $66 million as of March 31, 2017 and December 31, 2016, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements. We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2017 and December 31, 2016, substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $3 million at both March 31, 2017 and December 31, 2016. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. |
Inventory, Linefill and Base Gas and Long-term Inventory |
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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):
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Acquisitions and Dispositions |
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Mar. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combinations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions and Dispositions | Acquisitions and Dispositions Acquisitions The following acquisitions were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance. Alpha Crude Connector Acquisition On February 14, 2017, we acquired all of the issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration of approximately $1.217 billion, subject to working capital and other adjustments (the “ACC Acquisition”). The ACC Acquisition was initially funded through borrowings under PAA's senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from PAA's March 2017 issuance of its common units to AAP pursuant to the Omnibus Agreement and in connection with our underwritten equity offering. See Note 9 for additional information. Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises 515 miles of gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink. We intend to make additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements intended to increase the ACC System capacity to approximately 350,000 barrels per day, depending on the level of volume at each delivery point. The ACC System is supported by acreage dedications covering approximately 315,000 gross acres, and include a significant acreage dedication from one of the largest producers in the region. The ACC System complements our other Permian Basin assets and enhances the services available to the producers in the Northern Delaware Basin. The determination of the acquisition-date fair value of the assets acquired and liabilities assumed is preliminary. We expect to finalize our fair value determination in 2017. The following table reflects the preliminary fair value determination (in millions):
Intangible assets are included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. The preliminary determination of fair value to intangible assets above is comprised of five acreage dedication contracts and associated customer relationships that will be amortized over a remaining weighted average useful life of approximately 20 years. The value assigned to such intangible assets will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed. Amortization was approximately $1 million for the period ended March 31, 2017, and the future amortization is estimated as follows for the next five years (in millions):
Goodwill is an intangible asset representing the future economic benefits expected to be derived from other assets acquired that are not individually identified and separately recognized. The goodwill arising from the ACC Acquisition, which is tax deductible, represents the anticipated opportunities to generate future cash flows from undedicated acreage and the synergies created between the ACC System and our existing assets. The assets acquired in the ACC Acquisition, as well as the associated goodwill, are primarily included in our Transportation segment. During the three months ended March 31, 2017, we incurred approximately $5 million of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of general and administrative expenses in our Condensed Consolidated Statement of Operations. Pro forma financial information assuming the ACC Acquisition had occurred as of the beginning of the calendar year prior to the year of acquisition, as well as the revenues and earnings generated during the period, were not material for disclosure purposes. Other Acquisitions In February 2017, we acquired a propane marine terminal for cash consideration of approximately $41 million. The assets acquired are included in our Facilities segment. We did not recognize any goodwill related to this acquisition. Investment Acquisition On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) for a purchase price of $133 million through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our 50% share ($66.5 million), we contributed approximately 1.3 million PAA common units and approximately $26 million in cash. Advantage owns a 70-mile, 16-inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”). Noble will serve as operator and will construct a pipeline to deliver crude oil to the Advantage Pipeline from its central gathering facility in the southern Delaware Basin. We will construct a pipeline to connect our Wolfbone Ranch facility to the Advantage Pipeline near Highway 285 in Reeves County, Texas. The connections are estimated to be completed in 2017. The Advantage Pipeline is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Dispositions and Divestitures During the three months ended March 31, 2017, we sold certain non-core assets for proceeds of approximately $161 million. These sales primarily included (i) a non-core pipeline segment located in the Midwestern United States and (ii) a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma (the “Hewitt Segment”) for our net book value. We retained a 60% undivided interest in the Hewitt Segment and a 100% interest in the remaining portion of the Red River Pipeline that extends from Ardmore to Longview, Texas. We recognized a net gain of $36 million related to the sale of the non-core pipeline segment, including the write-off of a portion of the remaining book value, which is included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. Assets Held for Sale As of March 31, 2017, we classified approximately $490 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) primarily related to definitive agreements to sell non-core assets, including certain of our West Coast terminal assets and our Bluewater natural gas storage facility located in Michigan. The assets held for sale are primarily property and equipment and are included in our Facilities segment. We expect these transactions to close in the second quarter or early in the third quarter of 2017, subject to customary closing conditions, including the receipt of regulatory approvals. During the three months ended March 31, 2017, we recognized an impairment loss of $31 million related to assets held for sale. This impairment loss is included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. |
Goodwill |
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Goodwill | Goodwill Goodwill by segment and changes in goodwill are reflected in the following table (in millions):
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Debt |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt | Debt Debt consisted of the following (in millions):
Borrowings and Repayments Total borrowings under the credit facilities and the PAA commercial paper program for the three months ended March 31, 2017 and 2016 were approximately $18.8 billion and $10.8 billion, respectively. Total repayments under the credit facilities and the PAA commercial paper program were approximately $19.2 billion and $12.3 billion for the three months ended March 31, 2017 and 2016, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At March 31, 2017 and December 31, 2016, we had outstanding letters of credit of $77 million and $73 million, respectively. Senior Notes Repayments PAA's $400 million, 6.13% senior notes were repaid in January 2017. We utilized cash on hand and available capacity under PAA's commercial paper program and credit facilities to repay these notes. |
Partners' Capital and Distributions |
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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:
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Distributions The following table details the distributions paid to our Class A shareholders during or pertaining to the first three months of 2017 (in millions, except per share data):
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Sales of Class A Shares The following table summarizes our sales of Class A shares during the three months ended March 31, 2017 (net proceeds in millions):
(1) Amounts are net of costs associated with the offerings.
Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, we used the net proceeds from the sale of our Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA. See "—Subsidiary Sales of Common Units" below. The cash purchase by PAGP of additional units issued by AAP and corresponding cash purchase by AAP of additional common units issued by PAA results in the allocation of the fair value of the proceeds between controlling and noncontrolling interests in AAP and PAA based on their respective ownership percentages. Additionally, in accordance with ASC 810, an adjustment in partners' capital based on historical carrying value is recognized by PAGP's Class A shareholders on their increase in ownership of subsidiary entities and a corresponding adjustment is recognized in partners' capital by PAGP's noncontrolling interests due to the dilution of their ownership interest. The allocation to noncontrolling interests results from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in "Sales of Class A shares" on our Condensed Consolidated Statements of Changes in Partners' Capital. Consolidated Subsidiaries Noncontrolling Interests in Subsidiaries As of March 31, 2017, noncontrolling interests in our subsidiaries consisted of (i) a 63% limited partner interest in PAA, (ii) an approximate 47% limited partner interest in AAP and (iii) a 25% interest in SLC Pipeline LLC. Subsidiary Sales of Common Units Continuous Offering Program. During the three months ended March 31, 2017, PAA issued an aggregate of approximately 4.0 million common units under its continuous offering program, generating proceeds of $129 million, net of $1 million of commissions paid to its sales agents. The proceeds from the issuance of PAA common units were allocated among all of PAA’s common unitholders, including AAP, based on their percentage ownership of common units. Additionally, PAA’s capital attributable to AAP was adjusted based on historical carrying value, in accordance with ASC 810, to reflect the dilution of its interest in PAA as a result of the issuance of additional common units to the public unitholders. These adjustments were recognized by PAGP in proportion to PAGP’s ownership interest in AAP, which resulted in a net increase in partners’ capital attributable to PAGP resulting from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in "Sales of common units by a subsidiary" on our Condensed Consolidated Statements of Changes in Partners' Capital. Omnibus Agreement. During the three months ended March 31, 2017, pursuant to the Omnibus Agreement discussed above, PAA sold (i) approximately 1.8 million common units to AAP in connection with our issuance of Class A shares under our Continuous Offering Program and (ii) 48.3 million common units to AAP in connection with our underwritten offering. Subsidiary Distributions PAA Cash Distributions. The following table details the distributions to PAA’s partners paid in cash during or pertaining to the first three months of 2017 (in millions, except per unit data):
PAA In-Kind Distributions. On February 14, 2017, PAA issued 1,287,773 Series A preferred units in lieu of a cash distribution of $34 million on PAA's Series A preferred units outstanding as of the record date for such distribution. On May 15, 2017, PAA will issue 1,313,527 Series A preferred units in lieu of a cash distribution of $34 million on PAA's Series A preferred units outstanding as of the record date for such distribution. AAP Distributions. The following table details the distributions paid to AAP’s partners during or pertaining to the first three months of 2017 from distributions received from PAA (in millions):
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Other Distributions. During the three months ended March 31, 2017, distributions of $1 million were paid to noncontrolling interests in SLC Pipeline LLC. Deferred Tax Asset Impact from the Sale of Subsidiary Units In connection with the sales of AAP units and PAA common units referenced above, a deferred asset was created. The tax basis of PAGP’s purchase of the additional units was accounted for at fair market value for U.S. federal income tax purposes, but the GAAP basis was impacted by the adjustments that are based on historical carrying value. The resulting basis difference resulted in a deferred tax asset that was recorded as a component of partner’s capital as it results from transactions with shareholders. |
Derivatives and Risk Management Activities |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives and Risk Management Activities | Derivatives and Risk Management Activities We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Commodity Price Risk Hedging Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories: Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2017, net derivative positions related to these activities included:
Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of March 31, 2017, our PLA hedges included a long call option position of 0.8 million barrels through December 2018. Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of March 31, 2017, we had a long natural gas position of 56.7 Bcf which hedges our natural gas processing and operational needs through December 2018. We also had a short propane position of 10.1 million barrels through December 2018, a short butane position of 3.1 million barrels through December 2018 and a short WTI position of 1.0 million barrels through December 2018. In addition, we had a long power position of 0.4 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2018. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate risk associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest payments associated with the underlying debt. The following table summarizes the terms of our outstanding interest derivatives as of March 31, 2017 (notional amounts in millions):
Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards. As of March 31, 2017, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales. The following table summarizes our open forward exchange contracts as of March 31, 2017 (in millions):
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. At March 31, 2017, the fair value of this embedded derivative was a liability of approximately $36 million. We recognized a loss of approximately $4 million during the three months ended March 31, 2017. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional information regarding the Preferred Distribution Rate Reset Option. Summary of Financial Impact We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows. A summary of the impact of our derivative activities recognized in earnings is as follows (in millions):
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2017 (in millions):
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions):
Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties. Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable/(payable):
The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions):
As of March 31, 2017, there was a net loss of $219 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at March 31, 2017, we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The remaining deferred loss of $211 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of March 31, 2017; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions):
At March 31, 2017 and December 31, 2016, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us. Recurring Fair Value Measurements Derivative Financial Assets and Liabilities The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):
(1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. Level 1 Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets. Level 2 Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity contracts and the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which is classified as an embedded derivative. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. The fair value of the embedded derivative feature contained in 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 which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations as “Other income/(expense), net.” To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur. Rollforward of Level 3 Net Asset/(Liability) The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):
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Related Party Transactions |
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Related Party Transactions | Related Party Transactions See Note 15 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a complete discussion of our related party transactions. Transactions with Oxy As of March 31, 2017, Oxy had a representative on the board of directors of our general partner and owned approximately 10% of the limited partner interests in AAP. During the three months ended March 31, 2017 and 2016, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions):
We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
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Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery. Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed. At March 31, 2017, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $139 million, of which $59 million was classified as short-term and $80 million was classified as long-term. At December 31, 2016, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $147 million, of which $61 million was classified as short-term and $86 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At March 31, 2017, we had recorded receivables totaling $47 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $34 million was reflected in “Trade accounts receivable and other receivables, net” and $13 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. At December 31, 2016, we had recorded $56 million of such receivables, of which $39 million was reflected in “Trade accounts receivable and other receivables, net” and $17 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which includes the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean. As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending: On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO also obligates us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposes a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and requires us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational. No timeline has been established for the restart of Line 901 or Line 903. On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us, in the future. On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. To date, PHMSA has not issued a final order with respect to the 2013 Audit NOPV, nor has it assessed any fines or penalties with respect thereto; however, we cannot provide any assurances that any such fines or penalties will not be assessed against us. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The indictment included a total of 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts (currently three felony and seven misdemeanor charges) relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA intends to continue to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several of our employees and has expressed an interest in talking to other employees; consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims for payment as we receive them. In addition, we have also had nine class action lawsuits filed against us, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release, including potential classes such as commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or from persons or businesses who resold commercial seafood landed in such areas, retail businesses located in and around Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. To date, only the commercial fisherman and seafood reseller class has been certified by the court. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages. There have also been two securities law class action lawsuits filed on behalf of certain purported investors in PAA and/or PAGP against PAA, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of 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 claim unspecified damages as a result of the reduction in value of their investments in PAA and PAGP, which they attribute 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 may appeal or refile. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters. In addition, four unitholder derivative lawsuits have been filed by certain purported investors in PAA against PAA, certain of its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court. Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. The other remaining lawsuit was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of PAA during the period of time leading up to and following the Line 901 release. The plaintiffs in the two remaining lawsuits claim that PAA suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and have responded accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits. We have also had two lawsuits filed against us wherein the respective plaintiffs seek to compel the production of certain books and records that purportedly relate to the Line 901 incident, our alleged failure to comply with certain regulations and other matters. These lawsuits have been consolidated into a single proceeding in the Chancery Court for the State of Delaware. We have also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief. In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, as of March 31, 2017, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $280 million, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We accrued such estimate of aggregate total costs to “Field operating costs” primarily during 2015. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (iv) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident. As of March 31, 2017, we had a remaining undiscounted gross liability of $68 million related to this event, of which approximately $48 million is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through March 31, 2017, we had collected, subject to customary reservations, $156 million out of the approximate $197 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of March 31, 2017, we have recognized a receivable of approximately $41 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately $29 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheet, with the remainder in “Other long-term assets, net”. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. Mesa to Basin Pipeline. On January 6, 2016, PHMSA issued a Notice of Probable Violation and Proposed Civil Penalty relating to an approximate 500 barrel release of crude oil that took place on January 1, 2015 on our Mesa to Basin 12” pipeline in Midland, Texas. PHMSA conducted an accident investigation and reviewed documentation related to the incident, and concluded that we had committed probable violations of certain pipeline safety regulations. In the Notice, PHMSA maintains that we failed to carry out our written damage prevention program and to follow our pipeline excavation/ditching and backfill procedures on four separate occasions, and that such failures resulted in outside force damage that led to the January 1, 2015 release. In early March 2017, PHMSA issued a final order that concluded that we followed our pipeline excavation/ditching and backfill procedures, but maintained that we failed to carry out our written damage prevention program and imposed a civil penalty of $184,300. |
Operating Segments |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Segments | Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment. We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) gains or losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The following tables reflect certain financial data for each segment (in millions):
Segment Adjusted EBITDA Reconciliation The following table reconciles segment adjusted EBITDA to net income attributable to PAGP (in millions):
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Net Income Per Class A Share (Tables) |
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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):
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Inventory, Linefill and Base Gas and Long-term Inventory (Tables) |
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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):
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Acquisitions and Dispositions (Tables) |
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of assets acquired and liabilities assumed | The following table reflects the preliminary fair value determination (in millions):
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Schedule of finite lived intangible assets amortization expense | Amortization was approximately $1 million for the period ended March 31, 2017, and the future amortization is estimated as follows for the next five years (in millions):
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Goodwill (Tables) |
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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):
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Debt (Tables) |
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Mar. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of debt | Debt consisted of the following (in millions):
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Partners' Capital and Distributions (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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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:
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Schedule of sale of Class A shares | The following table summarizes our sales of Class A shares during the three months ended March 31, 2017 (net proceeds in millions):
(1) Amounts are net of costs associated with the offerings.
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PAA | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partners Capital and Distributions | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of distributions | The following table details the distributions to PAA’s partners paid in cash during or pertaining to the first three months of 2017 (in millions, except per unit data):
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AAP | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partners Capital and Distributions | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of distributions | The following table details the distributions paid to AAP’s partners during or pertaining to the first three months of 2017 from distributions received from PAA (in millions):
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Class A Shares | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partners Capital and Distributions | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of distributions | The following table details the distributions paid to our Class A shareholders during or pertaining to the first three months of 2017 (in millions, except per share data):
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Derivatives and Risk Management Activities (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives and Risk Management Activities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Impact of derivative activities recognized in earnings | A summary of the impact of our derivative activities recognized in earnings is as follows (in millions):
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Summary of derivative assets and liabilities on Condensed Consolidated Balance Sheets on a gross basis | The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2017 (in millions):
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions):
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Schedule of broker receivables and payables | The following table provides the components of our net broker receivable/(payable):
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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):
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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):
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Net deferred gain/(loss) recognized in AOCI for derivatives | The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions):
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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):
(1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. |
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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):
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Interest Rate Swaps | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives and Risk Management Activities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of terms of outstanding interest rate derivatives | The following table summarizes the terms of our outstanding interest derivatives as of March 31, 2017 (notional amounts in millions):
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Foreign Currency Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives and Risk Management Activities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Open forward exchange contracts | The following table summarizes our open forward exchange contracts as of March 31, 2017 (in millions):
|
Related Party Transactions (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oxy | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of related party transactions | The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions):
We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
|
Operating Segments (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment financial data | The following tables reflect certain financial data for each segment (in millions):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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):
|
Organization and Basis of Consolidation and Presentation - Organization/Reverse Stock Split (Details) shares in Millions |
3 Months Ended | |
---|---|---|
Nov. 15, 2016 |
Mar. 31, 2017
segment
shares
|
|
Organization and basis of presentation | ||
Operating segments number | segment | 3 | |
AAP | GP LLC | ||
Organization and basis of presentation | ||
Ownership interest in the subsidiary (units) | 1.0 | |
PAA | AAP | ||
Organization and basis of presentation | ||
Ownership interest in the subsidiary | 37.00% | |
Ownership interest in the subsidiary (units) | 288.3 | |
GP LLC | ||
Organization and basis of presentation | ||
Ownership interest in the subsidiary | 100.00% | |
AAP | ||
Organization and basis of presentation | ||
Ownership interest in the subsidiary | 53.00% | |
Ownership interest in the subsidiary (units) | 150.8 | |
Class Shares | ||
Organization and basis of presentation | ||
Reverse stock split conversion ratio | 0.3775 | |
Simplification Agreement | PAA GP | PAA | ||
Organization and basis of presentation | ||
Economic general partner interest converted into non-economic interest | 2.00% |
Accounts Receivable, Net (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended |
---|---|---|
Mar. 31, 2017 |
Dec. 31, 2016 |
|
Accounts Receivable, Net | ||
Advance cash payments received from third parties to mitigate credit risk | $ 81 | $ 89 |
Standby letters of credit | $ 46 | $ 66 |
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date | 30 days | 30 days |
Allowance for doubtful accounts receivable | $ 3 | $ 3 |
Acquisitions and Dispositions - Acquisitions (Details) $ in Millions |
1 Months Ended | 3 Months Ended | ||
---|---|---|---|---|
Feb. 14, 2017
USD ($)
a
bbl / d
market_interconnect
mi
|
Feb. 28, 2017
USD ($)
|
Mar. 31, 2017
USD ($)
|
Mar. 31, 2016
USD ($)
|
|
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 1,254 | $ 85 | ||
Acquisition related costs | 5 | |||
ACC Acquisition | ||||
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 1,217 | |||
Length of gathering and transmission lines (in miles) | mi | 515 | |||
Number of market interconnects | market_interconnect | 5 | |||
Additional volume enhancements to gathering system (in bbl per day) | bbl / d | 350,000 | |||
Area of acreage dedications (in acres) | a | 315,000 | |||
Acquisition related costs | $ 5 | |||
Propane marine terminal | ||||
Business Acquisition [Line Items] | ||||
Cash paid in connection with acquisitions | $ 41 |
Acquisitions and Dispositions - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions |
Feb. 14, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
---|---|---|---|
Business Acquisition [Line Items] | |||
Goodwill | $ 2,596 | $ 2,344 | |
ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment | $ 299 | ||
Intangible assets | 641 | ||
Goodwill | 278 | ||
Other (including $4 million of cash acquired) | (1) | ||
Total | $ 1,217 | ||
Finite lived intangible assets, useful life | 20 years | ||
Cash acquired | $ 4 | ||
Minimum | ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment, useful life | 3 years | ||
Maximum | ACC Acquisition | |||
Business Acquisition [Line Items] | |||
Property and equipment, useful life | 70 years |
Acquisitions and Dispositions - Amortization Expense (Details) - ACC Acquisition $ in Millions |
3 Months Ended | |
---|---|---|
Feb. 14, 2017
contract
|
Mar. 31, 2017
USD ($)
|
|
Business Acquisition [Line Items] | ||
Finite lived intangible assets, useful life | 20 years | |
Acreage dedication contracts | ||
Business Acquisition [Line Items] | ||
Number of acreage dedication contracts | contract | 5 | |
Finite lived intangible assets, useful life | 20 years | |
Amortization of finite lived intangible assets | $ 1 | |
Remainder of 2017 | 9 | |
2018 | 25 | |
2019 | 34 | |
2020 | 42 | |
2021 | $ 48 |
Acquisitions and Dispositions - Investment Acquisition (Details) - USD ($) shares in Millions, $ in Millions |
Apr. 03, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
---|---|---|---|
Schedule of Equity Method Investments [Line Items] | |||
Equity method investment | $ 2,469.0 | $ 2,343.0 | |
Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Cash consideration | $ 26.0 | ||
Ownership percentage | 50.00% | ||
Equity method investment | $ 66.5 | ||
Advantage Joint Venture | Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Cash consideration | $ 133.0 | ||
PAA | Common Units | Subsequent Event | Advantage | |||
Schedule of Equity Method Investments [Line Items] | |||
Contribution of common units (units) | 1.3 |
Acquisitions and Dispositions - Dispositions and Divestitures (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2017 |
Mar. 31, 2016 |
|
Dispositions | ||
Proceeds from sales of assets | $ 161 | $ 246 |
Disposed of by sale | ||
Dispositions | ||
Proceeds from sales of assets | 161 | |
Held for sale | Depreciation and amortization | ||
Dispositions | ||
Impairment related to assets held for sale | 31 | |
Held for sale | Other current assets | ||
Dispositions | ||
Assets classified as held for sale | $ 490 | |
Red River Pipeline | ||
Dispositions | ||
Interest percentage disposed of | 40.00% | |
Red River Pipeline, Hewitt Segment | ||
Dispositions | ||
Interest retained after disposal | 60.00% | |
Red River Pipeline from Ardmore to Longview | ||
Dispositions | ||
Interest retained after disposal | 100.00% | |
Non-Core Pipeline Segment | Disposed of by sale | Depreciation and amortization | ||
Dispositions | ||
Recognized gains/(losses) related to sales of assets, net | $ 36 |
Goodwill (Details) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2017
USD ($)
| |
Changes in goodwill | |
Beginning Balance | $ 2,344 |
Acquisitions | 278 |
Foreign currency translation adjustments | 3 |
Dispositions and reclassifications to assets held for sale | (29) |
Ending Balance | 2,596 |
Operating Segments | Transportation | |
Changes in goodwill | |
Beginning Balance | 806 |
Acquisitions | 278 |
Foreign currency translation adjustments | 2 |
Ending Balance | 1,086 |
Operating Segments | Facilities | |
Changes in goodwill | |
Beginning Balance | 1,034 |
Foreign currency translation adjustments | 1 |
Dispositions and reclassifications to assets held for sale | (29) |
Ending Balance | 1,006 |
Operating Segments | Supply and Logistics | |
Changes in goodwill | |
Beginning Balance | 504 |
Ending Balance | $ 504 |
Debt - Letters of Credit, Borrowings and Repayments (Details) - USD ($) $ in Millions |
1 Months Ended | 3 Months Ended | ||
---|---|---|---|---|
Jan. 31, 2017 |
Mar. 31, 2017 |
Mar. 31, 2016 |
Dec. 31, 2016 |
|
Debt | ||||
Repayments of PAA senior notes | $ 400 | $ 0 | ||
Letters of credit | ||||
Debt | ||||
Outstanding letters of credit | 77 | $ 73 | ||
Credit agreements and PAA commercial paper program | ||||
Debt | ||||
Total borrowings | 18,800 | 10,800 | ||
Total repayments | $ 19,200 | $ 12,300 | ||
6.13 percent senior notes due January 2017 | PAA senior notes | ||||
Debt | ||||
Repayments of PAA senior notes | $ 400 | |||
Debt instrument, interest rate | 6.13% | 6.13% |
Partners' Capital and Distributions - Distributions, Class A (Details) - Class A Shares - USD ($) $ / shares in Units, $ in Millions |
May 15, 2017 |
Feb. 14, 2017 |
---|---|---|
Distributions | ||
Distributions to Class A Shareholders | $ 57 | |
Distribution per Class A share, paid (usd per share) | $ 0.55 | |
Forecast | ||
Distributions | ||
Distributions to Class A Shareholders | $ 84 | |
Distribution per Class A share, paid (usd per share) | $ 0.55 |
Partners' Capital and Distributions - Sale of Class A Shares (Details) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2017
USD ($)
shares
| |
Subsidiary, Sale of Stock [Line Items] | |
Sale of Class A shares, net proceeds | $ 1,535 |
Class A Shares | |
Subsidiary, Sale of Stock [Line Items] | |
Sales of Class A shares (shares) | shares | 50,086,326 |
Sale of Class A shares, net proceeds | $ 1,535 |
Class A Shares | Continuous Offering Program | |
Subsidiary, Sale of Stock [Line Items] | |
Sales of Class A shares (shares) | shares | 1,786,326 |
Sale of Class A shares, net proceeds | $ 61 |
Commissions paid to sales agents | $ 1 |
Class A Shares | Underwritten Offering | |
Subsidiary, Sale of Stock [Line Items] | |
Sales of Class A shares (shares) | shares | 48,300,000 |
Sale of Class A shares, net proceeds | $ 1,474 |
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2017
USD ($)
contract
| |
8 forward starting interest rate swaps (30-year), 3.14% | |
Interest Rate Risk Hedging | |
Number of interest rate derivative contracts | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 3.14% |
8 forward starting interest rate swaps (30-year), 3.20% | |
Interest Rate Risk Hedging | |
Number of interest rate derivative contracts | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 3.20% |
8 forward starting interest rate swaps (30-year), 2.83% | |
Interest Rate Risk Hedging | |
Number of interest rate derivative contracts | contract | 8 |
Term of derivative contract | 30 years |
Notional amount of derivatives | $ | $ 200 |
Average rate locked (percent) | 2.83% |
Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) CAD in Millions, $ in Millions |
Mar. 31, 2017
CAD
CAD / $
|
Mar. 31, 2017
USD ($)
CAD / $
|
---|---|---|
Forward exchange contracts that exchange CAD For USD maturing 2017 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | CAD 234 | $ 175 |
Average exchange rate (cad per usd) | 1.34 | 1.34 |
Forward exchange contracts that exchange USD for CAD maturing in 2017 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | CAD 569 | $ 428 |
Average exchange rate (cad per usd) | 1.33 | 1.33 |
Derivatives and Risk Management Activities - Embedded Derivatives (Details) - Preferred Distribution Rate Reset Option - PAA - Series A Preferred Units $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2017
USD ($)
| |
Embedded Derivatives | |
Fair value of derivative liability | $ 36 |
Loss recognized due to changes in fair value | $ 4 |
Derivatives and Risk Management Activities - Net Broker Receivable/Payable (Details) - USD ($) $ in Millions |
Mar. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Initial margin | $ 92 | $ 119 |
Variation margin posted/(returned) | 3 | 291 |
Net broker receivable/(payable) | $ 95 | $ 410 |
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions |
Mar. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Asset Positions | ||
Gross Position - Asset | $ 96 | $ 108 |
Netting adjustment | (92) | (350) |
Cash collateral received | 95 | 410 |
Net Position - Asset | 99 | 168 |
Derivative Liability Positions | ||
Gross Position - Liability | (183) | (481) |
Netting adjustment | 92 | 350 |
Net Position - Liability | (91) | (131) |
Other current assets | ||
Derivative Asset Positions | ||
Net Position - Asset | 94 | 167 |
Other long-term assets, net | ||
Derivative Asset Positions | ||
Net Position - Asset | 5 | 1 |
Other current liabilities | ||
Derivative Liability Positions | ||
Net Position - Liability | (28) | (40) |
Other long-term liabilities and deferred credits | ||
Derivative Liability Positions | ||
Net Position - Liability | $ (63) | $ (91) |
Derivatives and Risk Management Activities - AOCI on Derivatives (Details) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2017
USD ($)
contract
|
Mar. 31, 2016
USD ($)
|
Dec. 31, 2016
contract
|
|
Derivatives, Fair Value [Line Items] | |||
Number of derivatives held with credit risk related contingent features | contract | 0 | 0 | |
Interest Rate Derivatives | |||
Derivatives, Fair Value [Line Items] | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | $ | $ 7 | $ (90) |
Related Party Transactions (Details) - Oxy - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2017 |
Mar. 31, 2016 |
Dec. 31, 2016 |
|
Related Party Transactions | |||
Revenues | $ 234 | $ 112 | |
Purchases and related costs | (40) | $ (46) | |
Trade accounts receivable and other receivables | 872 | $ 789 | |
Accounts payable | $ 818 | $ 836 | |
AAP | |||
Related Party Transactions | |||
Limited partner interest | 10.00% |
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