Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2016 | May. 02, 2016 | |
Document and Entity Information | ||
Entity Registrant Name | PLAINS ALL AMERICAN PIPELINE LP | |
Entity Central Index Key | 1,070,423 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2016 | |
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 | 397,730,991 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q1 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 36 | $ 27 |
Trade accounts receivable and other receivables, net | 1,549 | 1,785 |
Inventory | 877 | 916 |
Other current assets | 318 | 241 |
Total current assets | 2,780 | 2,969 |
PROPERTY AND EQUIPMENT | 15,875 | 15,654 |
Accumulated depreciation | (2,205) | (2,180) |
Property and equipment, net | 13,670 | 13,474 |
OTHER ASSETS | ||
Goodwill | 2,405 | 2,405 |
Investments in unconsolidated entities | 2,097 | 2,027 |
Linefill and base gas | 899 | 898 |
Long-term inventory | 112 | 129 |
Other long-term assets, net | 334 | 386 |
Total assets | 22,297 | 22,288 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 1,979 | 2,038 |
Short-term debt | 715 | 999 |
Other current liabilities | 369 | 370 |
Total current liabilities | 3,063 | 3,407 |
LONG-TERM LIABILITIES | ||
Senior notes, net of unamortized discounts and debt issuance costs | 9,126 | 9,698 |
Other long-term debt | 27 | 677 |
Other long-term liabilities and deferred credits | 710 | 567 |
Total long-term liabilities | $ 9,863 | $ 10,942 |
COMMITMENTS AND CONTINGENCIES (NOTE 10) | ||
PARTNERS' CAPITAL | ||
General partner | $ 330 | $ 301 |
Total partners' capital excluding noncontrolling interests | 9,313 | 7,881 |
Noncontrolling interests | 58 | 58 |
Total partners' capital | 9,371 | 7,939 |
Total liabilities and partners' capital | 22,297 | 22,288 |
Series A Preferred Units | ||
PARTNERS' CAPITAL | ||
Unitholders | 1,509 | |
Common Units | ||
PARTNERS' CAPITAL | ||
Unitholders | $ 7,474 | $ 7,580 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Mar. 31, 2016 | Dec. 31, 2015 |
Series A Preferred Units | ||
Units outstanding | 61,030,127 | |
Common Units | ||
Units outstanding | 397,730,991 | 397,727,624 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
REVENUES | ||
Supply and Logistics segment revenues | $ 3,819 | $ 5,632 |
Transportation segment revenues | 154 | 185 |
Facilities segment revenues | 138 | 125 |
Total revenues | 4,111 | 5,942 |
COSTS AND EXPENSES | ||
Purchases and related costs | 3,348 | 5,042 |
Field operating costs | 300 | 346 |
General and administrative expenses | 67 | 78 |
Depreciation and amortization | 114 | 104 |
Total costs and expenses | 3,829 | 5,570 |
OPERATING INCOME | 282 | 372 |
OTHER INCOME/(EXPENSE) | ||
Equity earnings in unconsolidated entities | 47 | 37 |
Interest expense (net of capitalized interest of $13 and $14, respectively) | (112) | (105) |
Other income/(expense), net | 5 | (4) |
INCOME BEFORE TAX | 222 | 300 |
Current income tax expense | (31) | (42) |
Deferred income tax benefit | 12 | 26 |
NET INCOME | 203 | 284 |
Net income attributable to noncontrolling interests | (1) | (1) |
NET INCOME ATTRIBUTABLE TO PAA | 202 | 283 |
NET INCOME PER COMMON UNIT (NOTE 3): | ||
Net income attributable to common unitholders - Basic | 28 | 136 |
Net income attributable to common unitholders - Diluted | $ 28 | $ 136 |
Common Units | ||
NET INCOME PER COMMON UNIT (NOTE 3): | ||
Basic weighted average common units outstanding (in units) | 398 | 383 |
Basic net income per common unit (in dollars per unit) | $ 0.07 | $ 0.36 |
Diluted weighted average common units outstanding (in units) | 399 | 385 |
Diluted net income per common unit (in dollars per unit) | $ 0.07 | $ 0.35 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||
Interest expense, capitalized interest | $ 13 | $ 14 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | ||
Net income | $ 203 | $ 284 |
Other comprehensive income/(loss) | 118 | (376) |
Comprehensive income/(loss) | 321 | (92) |
Comprehensive income attributable to noncontrolling interests | (1) | (1) |
Comprehensive income/(loss) attributable to PAA | $ 320 | $ (93) |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Balance at beginning of period | $ (1,081) | $ (467) |
Reclassification adjustments | 1 | (6) |
Deferred loss on cash flow hedges | (90) | (72) |
Currency translation adjustments | 207 | (298) |
Total period activity | 118 | (376) |
Balance at end of period | (963) | (843) |
Derivative Instruments | ||
Balance at beginning of period | (203) | (159) |
Reclassification adjustments | 1 | (6) |
Deferred loss on cash flow hedges | (90) | (72) |
Total period activity | (89) | (78) |
Balance at end of period | (292) | (237) |
Translation Adjustments | ||
Balance at beginning of period | (878) | (308) |
Currency translation adjustments | 207 | (298) |
Total period activity | 207 | (298) |
Balance at end of period | $ (671) | $ (606) |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income | $ 203 | $ 284 |
Reconciliation of net income to net cash provided by operating activities: | ||
Depreciation and amortization | 114 | 104 |
Equity-indexed compensation expense | 4 | 19 |
Inventory valuation adjustments | 3 | 24 |
Deferred income tax benefit | (12) | (26) |
Gain on foreign currency revaluation | (3) | (27) |
Equity earnings in unconsolidated entities | (47) | (37) |
Distributions from unconsolidated entities | 52 | 54 |
Other | 3 | (6) |
Changes in assets and liabilities, net of acquisitions | 318 | 343 |
Net cash provided by operating activities | 635 | 732 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Cash paid in connection with acquisitions | (85) | (64) |
Investments in unconsolidated entities | (75) | (65) |
Additions to property, equipment and other | (372) | (441) |
Cash paid for purchases of linefill and base gas | (96) | |
Proceeds from sales of assets | 246 | 1 |
Other investing activities | (1) | (1) |
Net cash used in investing activities | (287) | (666) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Net repayments under commercial paper program (Note 6) | (1,211) | (734) |
Net repayments under senior secured hedged inventory facility (Note 6) | (300) | |
Net proceeds from the sale of Series A preferred units and associated embedded derivative (Note 7) | 1,570 | |
Net proceeds from the sale of common units | 1,099 | |
Contributions from general partner | 33 | 22 |
Distributions paid to common unitholders (Note 7) | (278) | (254) |
Distributions paid to general partner (Note 7) | (155) | (136) |
Other financing activities | (2) | (3) |
Net cash used in financing activities | (343) | (6) |
Effect of translation adjustment on cash | 4 | (5) |
Net increase in cash and cash equivalents | 9 | 55 |
Cash and cash equivalents, beginning of period | 27 | 403 |
Cash and cash equivalents, end of period | 36 | 458 |
Cash paid for: | ||
Interest, net of amounts capitalized | 85 | 74 |
Income taxes, net of amounts refunded | $ 16 | $ 11 |
CONDENSED CONSOLIDATED STATEME9
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions | Limited PartnersSeries A Preferred UnitsPartners' Capital Excluding Noncontrolling Interests | Limited PartnersCommon UnitsPartners' Capital Excluding Noncontrolling Interests | General PartnerPartners' Capital Excluding Noncontrolling Interests | Partners' Capital Excluding Noncontrolling Interests | Noncontrolling Interests | Total |
Balance, beginning of period at Dec. 31, 2014 | $ 7,793 | $ 340 | $ 8,133 | $ 58 | $ 8,191 | |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 138 | 145 | 283 | 1 | 284 | |
Distributions | (254) | (136) | (390) | (1) | (391) | |
Sale of common units | 1,099 | 22 | 1,121 | 1,121 | ||
Other comprehensive income/(loss) | (369) | (7) | (376) | (376) | ||
Other | 6 | 1 | 7 | 7 | ||
Balance, end of period at Mar. 31, 2015 | 8,413 | 365 | 8,778 | 58 | 8,836 | |
Balance, beginning of period at Dec. 31, 2015 | 7,580 | 301 | 7,881 | 58 | 7,939 | |
Increase (Decrease) in Partners' Capital | ||||||
Net income | 55 | 147 | 202 | 1 | 203 | |
Distributions | (278) | (155) | (433) | (1) | (434) | |
Sale of Series A preferred units | $ 1,509 | 33 | 1,542 | 1,542 | ||
Other comprehensive income/(loss) | 115 | 3 | 118 | 118 | ||
Other | 2 | 1 | 3 | 3 | ||
Balance, end of period at Mar. 31, 2016 | $ 1,509 | $ 7,474 | $ 330 | $ 9,313 | $ 58 | $ 9,371 |
Organization and Basis of Conso
Organization and Basis of Consolidation and Presentation | 3 Months Ended |
Mar. 31, 2016 | |
Organization and Basis of Consolidation and Presentation | |
Organization and Basis of Consolidation and Presentation | Note 1—Organization and Basis of Consolidation and Presentation Organization Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries. We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 11 for further discussion of our operating segments. Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP LLC, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole member of GP LLC, and at March 31, 2016, owned an approximate 43% limited partner interest in AAP. GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to our “general partner,” as the context requires, include any or all of PAA GP LLC, AAP and GP LLC. Definitions Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar DERs = Distribution equivalent rights 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 MLP = Master limited partnership NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange Oxy = Occidental Petroleum Corporation or its subsidiaries PLA = Pipeline loss allowance SEC = United States Securities and Exchange Commission USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2015 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. 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. Such reclassifications include $3 million reclassified from “Depreciation and amortization” to “Interest expense, net” in our accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2015 due to the retrospective application of revised debt issuance costs guidance issued by the FASB, which we adopted during the fourth quarter of 2015. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2015 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, 2016 should not be taken as indicative of results to be expected for the entire year. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. |
Recent Accounting Pronouncement
Recent Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2016 | |
Recent Accounting Pronouncements | |
Recent Accounting Pronouncements | Note 2— Recent Accounting Pronouncements Except as discussed below and in our 2015 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, 2016 that are of significance or potential significance to us. In February 2016, the FASB issued guidance that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance will become effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We expect to adopt this guidance on January 1, 2017, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. |
Net Income Per Common Unit
Net Income Per Common Unit | 3 Months Ended |
Mar. 31, 2016 | |
Net Income Per Common Unit | |
Net Income Per Common Unit | Note 3—Net Income Per Common Unit Basic and diluted net income per common unit is determined pursuant to the two-class method for MLPs as prescribed in FASB guidance . The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our preferred unitholders, general partner, common unitholders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting the amount allocated to the preferred unitholders, the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of common units outstanding during the period. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. Diluted net income per common unit is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2016 as the effect was antidilutive. See Note 7 to our Condensed Consolidated Financial Statements for additional information regarding our Series A preferred units. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs. The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Three Months Ended March 31, 2016 2015 Basic Net Income per Common Unit Net income attributable to PAA $ $ Less: Distributions to Series A preferred units (1) ) — Less: Distributions to general partner (1) ) ) Less: Distributions to participating securities (1) ) ) Less: Undistributed loss allocated to general partner (1) Net income attributable to common unitholders in accordance with application of the two-class method for MLPs $ $ Basic weighted average common units outstanding Basic net income per common unit $ $ Diluted Net Income per Common Unit Net income attributable to PAA $ $ Less: Distributions to Series A preferred units (1) ) — Less: Distributions to general partner (1) ) ) Less: Distributions to participating securities (1) ) ) Less: Undistributed loss allocated to general partner (1) Net income attributable to common unitholders in accordance with application of the two-class method for MLPs $ $ Basic weighted average common units outstanding Effect of dilutive securities: Weighted average LTIP units Diluted weighted average common units outstanding Diluted net income per common unit $ $ (1) We calculate net income attributable to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method. Pursuant to the terms of our partnership agreement, the general partner’s incentive distribution is limited to a percentage of available cash, which, as defined in our partnership agreement, is net of reserves deemed appropriate. As such, IDRs are not allocated undistributed earnings or distributions in excess of earnings in the calculation of net income per common unit. If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of our partnership agreement, basic and diluted net income per common unit as reflected in the table above would not have been impacted, as we did not have undistributed earnings for any of the periods presented. |
Accounts Receivable, Net
Accounts Receivable, Net | 3 Months Ended |
Mar. 31, 2016 | |
Accounts Receivable, Net | |
Accounts Receivable, Net | Note 4— 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, 2016 and December 31, 2015, we had received $52 million and $88 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $26 million and $36 million as of March 31, 2016 and December 31, 2015, 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, 2016 and December 31, 2015, 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 $4 million at both March 31, 2016 and December 31, 2015. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. |
Inventory, Linefill and Base Ga
Inventory, Linefill and Base Gas and Long-term Inventory | 3 Months Ended |
Mar. 31, 2016 | |
Inventory, Linefill and Base Gas and Long-term Inventory | |
Inventory, Linefill and Base Gas and Long-term Inventory | Note 5—Inventory, Linefill and Base Gas and Long-term Inventory Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): March 31, 2016 December 31, 2015 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil barrels $ $ barrels $ $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Other N/A N/A N/A N/A Inventory subtotal Linefill and base gas Crude oil barrels $ barrels $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Linefill and base gas subtotal Long-term inventory Crude oil barrels $ barrels $ NGL barrels $ barrels $ Long-term inventory subtotal Total $ $ (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. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $24 million during the three months ended March 31, 2015 primarily related to the writedown of our NGL inventory due to declines in prices. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014. See Note 8 for discussion of our derivative and risk management activities. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2016 | |
Debt | |
Debt | Note 6—Debt Debt consisted of the following (in millions): March 31, December 31, 2016 2015 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively (1) $ $ Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.4% (1) — Senior notes: 5.88% senior notes due August 2016 — 6.13% senior notes due January 2017 — Other Total short-term debt LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $74 and $77, respectively Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively Other Total long-term debt Total debt (2) $ $ (1) We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2016 and December 31, 2015, 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) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.8 billion as of both March 31, 2016 and December 31, 2015. We estimated the aggregate fair value of these notes as of March 31, 2016 and December 31, 2015 to be approximately $9.0 billion and $8.6 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Borrowings and Repayments Total borrowings under our credit facilities and commercial paper program for the three months ended March 31, 2016 and 2015 were approximately $10.8 billion and $7.0 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $12.3 billion and $7.7 billion for the three months ended March 31, 2016 and 2015, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase 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, 2016 and December 31, 2015, we had outstanding letters of credit of $45 million and $46 million, respectively. |
Partners' Capital and Distribut
Partners' Capital and Distributions | 3 Months Ended |
Mar. 31, 2016 | |
Partners' Capital and Distributions | |
Partners' Capital and Distributions | Note 7—Partners’ Capital and Distributions Units Outstanding The following tables present the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2015 — Sale of Series A preferred units — Issuance of common units under LTIP — Outstanding at March 31, 2016 Limited Partners Common Units Outstanding at December 31, 2014 Sale of common units Outstanding at March 31, 2015 Equity Offerings Series A Preferred Unit Offering. In January 2016, we completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in us for a cash purchase price of $26.25 per unit (the “Issue Price”). The Series A preferred units are a new class of equity security that ranks senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units will receive cumulative quarterly distributions, subject to customary antidilution adjustments, equal to an annual rate of 8% of the Issue Price ($2.10 per unit annualized). With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we may elect to pay distributions on the Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash. Our general partner will be entitled to participate in cash distributions on the Series A preferred units equal to its 2% general partner interest. The purchasers may convert their Series A preferred units, generally on a one-for-one basis and subject to customary antidilution adjustments, at any time after the second anniversary of the issuance date (or prior to a liquidation), in whole or in part, subject to certain minimum conversion amounts. We may convert the Series A preferred units at any time (but not more often than once per quarter) after the third anniversary of the issuance date, in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150% of the Issue Price for the preceding 20 trading days. The Series A preferred units will vote on an as-converted basis with our common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units to common units at the then applicable conversion rate. For a period of 30 days following (a) the fifth anniversary of the issuance date of the Series A preferred units and (b) each subsequent anniversary of the issuance date, the holders of the Series A preferred units, acting by majority vote, may make a one-time election to reset the distribution rate to equal the then applicable rate of the ten-year U.S. Treasury plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 8 for additional information. If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the issuance date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95% of the volume-weighted average price of the common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions. Distributions Cash Distributions . The following table details the distributions paid in cash during or pertaining to the first three months of 2016, net of reductions to the general partner’s incentive distributions (in millions, except per unit data): Distributions Paid Distributions per Date Declared Distribution Date Common Unitholders General Partner Total common unit April 7, 2016 May 13, 2016 (1) $ $ $ $ January 12, 2016 February 12, 2016 $ $ $ $ (1) Payable to unitholders of record at the close of business on April 29, 2016 for the period January 1, 2016 through March 31, 2016. In-Kind Distributions . On May 13, 2016, we will issue 858,439 additional Series A preferred units in lieu of a cash distribution of $23 million. Such distribution is prorated for the period beginning on January 28, 2016, the issuance date of the Series A preferred units, through March 31, 2016 and will be issued to Series A preferred unitholders of record as of April 29, 2016. Since the May 13, 2016 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of March 31, 2016 and thus had no net impact on the Series A preferred unitholders’ capital account. Noncontrolling Interests in Subsidiaries As of March 31, 2016, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC. |
Derivatives and Risk Management
Derivatives and Risk Management Activities | 3 Months Ended |
Mar. 31, 2016 | |
Derivatives and Risk Management Activities | |
Derivatives and Risk Management Activities | Note 8—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 (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity 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, 2016, net derivative positions related to these activities included: · An average of 146,300 barrels per day net long position (total of 4.4 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2016 to match monthly average pricing. · A net short time spread position averaging 10,000 barrels per day (total of 4.3 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2017. · An average of 2,600 barrels per day (total of 1.2 million barrels) of crude oil grade spread positions through June 2017. These derivatives allow us to lock in grade basis differentials. · A net short position of 13.9 Bcf through April 2017 related to anticipated sales of natural gas inventory and base gas requirements. · A net short position of 25.8 million barrels through December 2018 related to anticipated net sales of our crude oil and NGL inventory. Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of March 31, 2016, our material PLA hedges included a long call option position of 1.4 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, 2016, we had a long natural gas position of 14.0 Bcf through December 2016, a short propane position of 2.7 million barrels through December 2016, a short butane position of 0.8 million barrels through December 2016 and a short WTI position of 0.3 million barrels through December 2016. 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 interest rate risk associated with anticipated and outstanding 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. As of March 31, 2016, AOCI includes deferred losses of $270 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments. We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2016 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2016 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2017 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2018 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/14/2019 % Cash flow hedge Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards. As of March 31, 2016, 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, 2016 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2016 $ $ $1.00 - $1.30 Forward exchange contracts that exchange USD for CAD: 2016 $ $ $1.00 - $1.33 Preferred Distribution Rate Reset Option A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At March 31, 2016, the fair value of this embedded derivative was a liability of approximately $60 million. See Note 7 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option. Summary of Financial Impact We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows. A summary of the impact of our derivative activities recognized in earnings is as follows (in millions): Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 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 $ $ $ $ $ ) $ ) Transportation segment revenues — — Field operating costs — ) ) — ) ) Interest Rate Derivatives Interest expense, net ) — ) ) — ) Foreign Currency Derivatives Supply and Logistics segment revenues — — ) ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ ) $ $ $ $ ) $ ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Location Value Location Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Interest rate derivatives Other current liabilities ) Other long-term liabilities and deferred credits ) Total derivatives designated as hedging instruments $ $ ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Other current liabilities Other current liabilities ) Other long-term liabilities and deferred credits Other long-term liabilities and deferred credits ) Foreign currency derivatives Other current assets Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits ) Total derivatives not designated as hedging instruments $ $ ) Total derivatives $ $ ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Location Value Location Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Interest rate derivatives Other long-term assets, net Other current liabilities ) Other long-term liabilities and deferred credits ) Total derivatives designated as hedging instruments $ $ ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Other long-term assets, net Other long-term assets, net ) Other current liabilities ) Other long-term liabilities and deferred credits ) Foreign currency derivatives Other current liabilities ) Total derivatives not designated as hedging instruments $ $ ) Total derivatives $ $ ) 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. As of March 31, 2016, we had a net broker payable of $17 million (consisting of initial margin of $70 million reduced by $87 million of variation margin that had been returned to us). As of December 31, 2015, we had a net broker payable of $156 million (consisting of initial margin of $91 million reduced by $247 million of variation margin that had been returned to us). The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): March 31, 2016 December 31, 2015 Derivative Derivative Derivative Derivative Asset Positions Liability Positions Asset Positions Liability Positions Netting Adjustments: Gross position - asset/(liability) $ $ ) $ $ ) Netting adjustment ) ) Cash collateral received ) — ) — Net position - asset/(liability) $ $ ) $ $ ) Balance Sheet Location After Netting Adjustments: Other current assets $ $ — $ $ — Other long-term assets, net — — — Other current liabilities — ) — ) Other long-term liabilities and deferred credits — ) — ) $ $ ) $ $ ) As of March 31, 2016, there was a net loss of $292 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, 2016, we expect to reclassify a net loss of $5 million to earnings in the next twelve months. The remaining deferred loss of $287 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of March 31, 2016; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended March 31, 2016 2015 Commodity derivatives, net $ — $ Interest rate derivatives, net ) ) Total $ ) $ ) At March 31, 2016 and December 31, 2015, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us. Recurring Fair Value Measurements Derivative Financial Assets and Liabilities The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions): Fair Value as of March 31, 2016 Fair Value as of December 31, 2015 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ $ $ $ $ $ $ $ Interest rate derivatives — ) — ) — ) — ) Foreign currency derivatives — — — ) — ) Preferred Distribution Rate Reset Option — — ) ) — — — — Total net derivative asset/(liability) $ $ ) $ ) $ ) $ $ $ $ (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. Level 1 Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets. Level 2 Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity contracts and the Preferred Distribution Rate Reset Option contained in our Series A preferred unit offering classified as an embedded derivative. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. The fair value of the embedded derivative feature contained in our Series A preferred units is based on a valuation model that estimates the future fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our future common unit price, future ten-year U.S. treasury rates, future default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations as “Other income/(expense), net.” To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur. Rollforward of Level 3 Net Asset/(Liability) The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions): Three Months Ended March 31, 2016 2015 Beginning Balance $ $ Losses for the period included in earnings ) — Settlements ) ) Derivatives entered into during the period ) Ending Balance $ ) $ Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ ) $ |
Related Party Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2016 | |
Related Party Transactions | |
Related Party Transactions | Note 9—Related Party Transactions See Note 14 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K for a complete discussion of our related party transactions. Transactions with Oxy As of March 31, 2016, Oxy owned approximately 13% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC. During the three months ended March 31, 2016 and 2015, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions): Three Months Ended March 31, 2016 2015 Revenues $ $ Purchases and related costs (1) $ ) $ (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed Consolidated Statements of Operations. We currently have a netting arrangement with O xy . Our gross receivable and payable amounts with O xy on our Condensed Consolidated Balance Sheets were as follows (in millions): March 31, December 31, 2016 2015 Trade accounts receivable and other receivables $ $ Accounts payable $ $ |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2016 | |
Commitments and Contingencies | |
Commitments and Contingencies | Note 10—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, 2016, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $176 million, of which $69 million was classified as short-term and $107 million was classified as long-term. At December 31, 2015, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $185 million, of which $81 million was classified as short-term and $104 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, 2016 and December 31, 2015, we had recorded receivables totaling $81 million and $161 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident . In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which 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, subject to continued shoreline monitoring. The cause of the release remains under investigation. Our current “worst case” estimate of the amount of oil spilled, representing the maximum volume of oil that we believed could have been spilled based on relevant facts, data and information, is approximately 2,935 barrels. As a result of the Line 901 incident, several governmental agencies and regulators have 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. On June 3, 2015, the corrective action order was amended to require us to take additional corrective actions with respect to both Lines 901 and 903, and on November 13, 2015, the corrective action order was further amended to require the purge and shutdown of Line 903 between Gaviota and Pentland (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 Line 903 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. 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 pursued any such civil or criminal charges with respect to the Line 901 release, there can be no assurance that such fines or penalties will not be imposed upon us, or that such civil or criminal charges will not be 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, on behalf of the EPA, 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. In addition to the DOJ, the California Attorney General’s Office and the District Attorney’s Office for the County of Santa Barbara are also investigating the Line 901 incident to determine whether any applicable state or local laws have been violated. On August 26, 2015, we also received a Request for Information from the EPA relating to Line 901 and we are in the process of responding to such request. While to date no civil or criminal charges with respect to the Line 901 release have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, California Attorney General or Santa Barbara County District Attorney, and no fines or penalties have been imposed by such governmental agencies, there can be no assurance that such fines or penalties will not be imposed upon us, our officers or our employees, or that such civil or criminal charges will not be 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 eight class action lawsuits filed against us, seven 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 persons that derive a significant portion of their income through commercial fishing and harvesting activities in the waters adjacent to Santa Barbara County or from businesses that are dependent on marine resources from Santa Barbara County, retail businesses located in historic downtown 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. There have also been two securities law class action lawsuits filed on behalf of certain purported investors in the Partnership and/or PAGP against the Partnership, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of the Partnership’s pipelines and related facilities through false and misleading statements, omission of material facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attribute to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, deny the allegations in these lawsuits and intend to respond 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 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, three unitholder derivative lawsuits have been filed by certain purported investors in the Partnership against the Partnership, certain of its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and the other was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs claim that the Partnership suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and intend to respond 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 in the Chancery Court for the State of Delaware 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. 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, 2016, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $269 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. 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 expected number of days that monitoring services will be required, (ii) the duration of the natural resource damage assessment and the ultimate amount of damages determined, (iii) 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, (iv) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (v) 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, 2016, we had a remaining undiscounted gross liability of $104 million related to this event, the majority of which is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. 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, 2016, we had collected, subject to customary reservations, $112 million out of the approximate $186 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of March 31, 2016, we have recognized a receivable of approximately $74 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. A majority of this receivable has been recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheet. We have substantially completed the clean-up and remediation efforts, excluding long-term site monitoring activities; however, we expect to make payments for additional costs associated with restoration and monitoring of the area, as well as natural resource damage assessment, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. MP29 Release. On July 10, 2015 , we experienced a crude oil release of approximately 100 barrels at our Pocahontas Pump Station near the border of Bond and Madison Counties in Illinois, approximately 40 miles from St. Louis, Missouri. The Pocahontas Station is part of the Capwood pipeline that runs from our Patoka Station to Wood River, Illinois. A portion of the released crude oil was contained within our Pocahontas facility, but some of the released crude oil entered a nearby waterway where it was contained with booms. On July 14, 2015, PHMSA issued a corrective action order requiring us to take various actions in response to the release, including remediation, reporting and other actions. As of December 18, 2015, we had submitted all requested information and reports required by the corrective action order and are currently awaiting PHMSA’s comment or approval. On August 10, 2015, we received a Notice of Violation from the Illinois Environmental Protection Agency (the “Agency”) alleging violations relating to the release and outlining the activities recommended by the Agency to resolve the alleged violations, including the completion of an investigation and various remediation activities. The Agency approved a work plan describing remediation activities proposed for remaining hydrocarbons at Pocahontas Station and affected waterways. Remediation activities under this work plan have effectively been completed, and on December 17, 2015, we entered into a Compliance Commitment Agreement with the Agency, which provides the framework for final completion and documentation of the remediation effort. 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. In connection with this incident, we have also had one class action lawsuit filed against us in the United States District Court for the Southern District of Illinois, which was subsequently voluntarily dismissed by the plaintiff. We estimate that the aggregate total costs associated with this release will be less than $10 million. 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. PHMSA’s compliance officer has recommended that we be assessed a civil penalty of $190,000. We have formally responded to PHMSA regarding this matter, but at this point we can provide no assurance regarding the final disposition of this matter or the final amount of any civil penalties. |
Operating Segments
Operating Segments | 3 Months Ended |
Mar. 31, 2016 | |
Operating Segments | |
Operating Segments | Note 11—Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit 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. Each of the items above 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 table reflects certain financial data for each segment (in millions): Three Months Ended March 31, 2016 Transportation Facilities Supply and Logistics Total Revenues: External Customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Three Months Ended March 31, 2015 Transportation Facilities Supply and Logistics Total Revenues: External Customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ (1) 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. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2015 Annual Report on Form 10-K. (2) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $2 million and $1 million for the three months ended March 31, 2016 and 2015, respectively. (3) The following table reconciles segment profit to net income attributable to PAA (in millions): Three Months Ended March 31, 2016 2015 Segment profit $ $ Depreciation and amortization ) ) Interest expense, net ) ) Other income/(expense), net ) Income before tax Income tax expense ) ) Net income Net income attributable to noncontrolling interests ) ) Net income attributable to PAA $ $ |
Acquisitions and Dispositions
Acquisitions and Dispositions | 3 Months Ended |
Mar. 31, 2016 | |
Acquisitions and Dispositions | |
Acquisitions and Dispositions | Note 12—Acquisitions and Dispositions Acquisitions . During the first quarter of 2016, we completed one acquisition for cash consideration of $85 million. We did not recognize any goodwill related to this acquisition. Dispositions . In the first quarter of 2016, we entered into definitive agreements to sell several non-core assets. A portion of these transactions closed in March, and we expect the sale of the remaining assets to be consummated in the second quarter of 2016, subject to customary closing conditions, as applicable. As of March 31, 2016, we classified approximately $120 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”). During the three months ended March 31, 2016, we recognized gains of approximately $56 million and impairment losses of $50 million related to these non-core asset sales, including $15 million of impairment of goodwill included in a disposal group classified as held for sale. These gains and impairment losses are included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. |
Net Income Per Common Unit (Tab
Net Income Per Common Unit (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Net Income Per Common Unit | |
Computation of basic and diluted net income per common unit | The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data): Three Months Ended March 31, 2016 2015 Basic Net Income per Common Unit Net income attributable to PAA $ $ Less: Distributions to Series A preferred units (1) ) — Less: Distributions to general partner (1) ) ) Less: Distributions to participating securities (1) ) ) Less: Undistributed loss allocated to general partner (1) Net income attributable to common unitholders in accordance with application of the two-class method for MLPs $ $ Basic weighted average common units outstanding Basic net income per common unit $ $ Diluted Net Income per Common Unit Net income attributable to PAA $ $ Less: Distributions to Series A preferred units (1) ) — Less: Distributions to general partner (1) ) ) Less: Distributions to participating securities (1) ) ) Less: Undistributed loss allocated to general partner (1) Net income attributable to common unitholders in accordance with application of the two-class method for MLPs $ $ Basic weighted average common units outstanding Effect of dilutive securities: Weighted average LTIP units Diluted weighted average common units outstanding Diluted net income per common unit $ $ (1) We calculate net income attributable to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method. |
Inventory, Linefill and Base 23
Inventory, Linefill and Base Gas and Long-term Inventory (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Inventory, Linefill and Base Gas and Long-term Inventory | |
Schedule of inventory, linefill and base gas and long-term inventory | Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions): March 31, 2016 December 31, 2015 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil barrels $ $ barrels $ $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Other N/A N/A N/A N/A Inventory subtotal Linefill and base gas Crude oil barrels $ barrels $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Linefill and base gas subtotal Long-term inventory Crude oil barrels $ barrels $ NGL barrels $ barrels $ Long-term inventory subtotal Total $ $ (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. |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Debt | |
Schedule of debt | Debt consisted of the following (in millions): March 31, December 31, 2016 2015 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively (1) $ $ Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.4% (1) — Senior notes: 5.88% senior notes due August 2016 — 6.13% senior notes due January 2017 — Other Total short-term debt LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $74 and $77, respectively Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively Other Total long-term debt Total debt (2) $ $ (1) We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2016 and December 31, 2015, 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) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.8 billion as of both March 31, 2016 and December 31, 2015. We estimated the aggregate fair value of these notes as of March 31, 2016 and December 31, 2015 to be approximately $9.0 billion and $8.6 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. |
Partners' Capital and Distrib25
Partners' Capital and Distributions (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Partners' Capital and Distributions | |
Schedule of activity for Series A preferred units and common units | The following tables present the activity for our Series A preferred units and common units: Limited Partners Preferred Units Common Units Outstanding at December 31, 2015 — Sale of Series A preferred units — Issuance of common units under LTIP — Outstanding at March 31, 2016 Limited Partners Common Units Outstanding at December 31, 2014 Sale of common units Outstanding at March 31, 2015 |
Schedule of distributions paid in cash, net of reductions in the general partner's incentive distributions | The following table details the distributions paid in cash during or pertaining to the first three months of 2016, net of reductions to the general partner’s incentive distributions (in millions, except per unit data): Distributions Paid Distributions per Date Declared Distribution Date Common Unitholders General Partner Total common unit April 7, 2016 May 13, 2016 (1) $ $ $ $ January 12, 2016 February 12, 2016 $ $ $ $ (1) Payable to unitholders of record at the close of business on April 29, 2016 for the period January 1, 2016 through March 31, 2016. |
Derivatives and Risk Manageme26
Derivatives and Risk Management Activities (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Derivatives and Risk Management Activities | |
Impact of derivative activities recognized in earnings | A summary of the impact of our derivative activities recognized in earnings is as follows (in millions): Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 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 $ $ $ $ $ ) $ ) Transportation segment revenues — — Field operating costs — ) ) — ) ) Interest Rate Derivatives Interest expense, net ) — ) ) — ) Foreign Currency Derivatives Supply and Logistics segment revenues — — ) ) Total Gain/(Loss) on Derivatives Recognized in Net Income $ ) $ $ $ $ ) $ ) |
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, 2016 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Location Value Location Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Interest rate derivatives Other current liabilities ) Other long-term liabilities and deferred credits ) Total derivatives designated as hedging instruments $ $ ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Other current liabilities Other current liabilities ) Other long-term liabilities and deferred credits Other long-term liabilities and deferred credits ) Foreign currency derivatives Other current assets Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits ) Total derivatives not designated as hedging instruments $ $ ) Total derivatives $ $ ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Location Value Location Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Interest rate derivatives Other long-term assets, net Other current liabilities ) Other long-term liabilities and deferred credits ) Total derivatives designated as hedging instruments $ $ ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ ) Other long-term assets, net Other long-term assets, net ) Other current liabilities ) Other long-term liabilities and deferred credits ) Foreign currency derivatives Other current liabilities ) Total derivatives not designated as hedging instruments $ $ ) Total derivatives $ $ ) |
Schedule of derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements | The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): March 31, 2016 December 31, 2015 Derivative Derivative Derivative Derivative Asset Positions Liability Positions Asset Positions Liability Positions Netting Adjustments: Gross position - asset/(liability) $ $ ) $ $ ) Netting adjustment ) ) Cash collateral received ) — ) — Net position - asset/(liability) $ $ ) $ $ ) Balance Sheet Location After Netting Adjustments: Other current assets $ $ — $ $ — Other long-term assets, net — — — Other current liabilities — ) — ) Other long-term liabilities and deferred credits — ) — ) $ $ ) $ $ ) |
Net deferred gain/(loss) recognized in AOCI for derivatives | The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended March 31, 2016 2015 Commodity derivatives, net $ — $ Interest rate derivatives, net ) ) Total $ ) $ ) |
Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy | The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions): Fair Value as of March 31, 2016 Fair Value as of December 31, 2015 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ $ $ $ $ $ $ $ Interest rate derivatives — ) — ) — ) — ) Foreign currency derivatives — — — ) — ) Preferred Distribution Rate Reset Option — — ) ) — — — — Total net derivative asset/(liability) $ $ ) $ ) $ ) $ $ $ $ (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. |
Reconciliation of changes in fair value of derivatives classified as Level 3 | The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions): Three Months Ended March 31, 2016 2015 Beginning Balance $ $ Losses for the period included in earnings ) — Settlements ) ) Derivatives entered into during the period ) Ending Balance $ ) $ Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ ) $ |
Interest Rate Swaps | |
Derivatives and Risk Management Activities | |
Schedule of terms of forward starting interest rate swaps | The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2016 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2016 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2017 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2018 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/14/2019 % Cash flow hedge |
Foreign Currency Derivatives | |
Derivatives and Risk Management Activities | |
Summary of open forward exchange contracts | The following table summarizes our open forward exchange contracts as of March 31, 2016 (in millions): USD CAD Average Exchange Rate USD to CAD Forward exchange contracts that exchange CAD for USD: 2016 $ $ $1.00 - $1.30 Forward exchange contracts that exchange USD for CAD: 2016 $ $ $1.00 - $1.33 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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): Three Months Ended March 31, 2016 2015 Revenues $ $ Purchases and related costs (1) $ ) $ (1) Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed Consolidated Statements of Operations. We currently have a netting arrangement with O xy . Our gross receivable and payable amounts with O xy on our Condensed Consolidated Balance Sheets were as follows (in millions): March 31, December 31, 2016 2015 Trade accounts receivable and other receivables $ $ Accounts payable $ $ |
Operating Segments (Tables)
Operating Segments (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Operating Segments | |
Segment financial data | The following table reflects certain financial data for each segment (in millions): Three Months Ended March 31, 2016 Transportation Facilities Supply and Logistics Total Revenues: External Customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Three Months Ended March 31, 2015 Transportation Facilities Supply and Logistics Total Revenues: External Customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ (1) 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. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2015 Annual Report on Form 10-K. (2) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $2 million and $1 million for the three months ended March 31, 2016 and 2015, respectively. (3) The following table reconciles segment profit to net income attributable to PAA (in millions): Three Months Ended March 31, 2016 2015 Segment profit $ $ Depreciation and amortization ) ) Interest expense, net ) ) Other income/(expense), net ) Income before tax Income tax expense ) ) Net income Net income attributable to noncontrolling interests ) ) Net income attributable to PAA $ $ |
Reconciliation of segment profit to net income attributable to PAA | The following table reconciles segment profit to net income attributable to PAA (in millions): Three Months Ended March 31, 2016 2015 Segment profit $ $ Depreciation and amortization ) ) Interest expense, net ) ) Other income/(expense), net ) Income before tax Income tax expense ) ) Net income Net income attributable to noncontrolling interests ) ) Net income attributable to PAA $ $ |
Organization and Basis of Con29
Organization and Basis of Consolidation and Presentation - Segments and Ownership (Details) | 3 Months Ended |
Mar. 31, 2016segment | |
Organization | |
Operating segments number | 3 |
General partner ownership interest (as a percent) | 2.00% |
AAP | PAGP | |
Organization | |
Limited partner interest (as a percent) | 43.00% |
Organization and Basis of Con30
Organization and Basis of Consolidation and Presentation - Debt Issuance Costs (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Basis of Consolidation and Presentation | ||
Depreciation and amortization | $ 114 | $ 104 |
Interest expense, net | $ 112 | 105 |
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs | Reclassification due to retrospective application of revised guidance | ||
Basis of Consolidation and Presentation | ||
Depreciation and amortization | (3) | |
Interest expense, net | $ 3 |
Net Income Per Common Unit (Det
Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Basic Net Income per Common Unit | ||
Net income attributable to PAA | $ 202 | $ 283 |
Less: Distributions to Series A Preferred Units | (23) | |
Less: Distributions to general partner | (155) | (148) |
Less: Distributions to participating securities | (1) | (2) |
Less: Undistributed loss allocated to general partner | 5 | 3 |
Net income attributable to common unitholders in accordance with application of the two-class method for MLPs | 28 | 136 |
Diluted Net Income per Common Unit | ||
Net income attributable to PAA | 202 | 283 |
Less: Distributions to Series A Preferred Units | (23) | |
Less: Distributions to general partner | (155) | (148) |
Less: Distributions to participating securities | (1) | (2) |
Less: Undistributed loss allocated to general partner | 5 | 3 |
Net income attributable to common unitholders in accordance with application of the two-class method for MLPs | $ 28 | $ 136 |
Common Units | ||
Basic Net Income per Common Unit | ||
Basic weighted average common units outstanding (in units) | 398 | 383 |
Basic net income per common unit (in dollars per unit) | $ 0.07 | $ 0.36 |
Diluted Net Income per Common Unit | ||
Basic weighted average common units outstanding (in units) | 398 | 383 |
Effect of dilutive securities: Weighted average LTIP units | 1 | 2 |
Diluted weighted average common units outstanding | 399 | 385 |
Diluted net income per common unit (in dollars per unit) | $ 0.07 | $ 0.35 |
Accounts Receivable, Net (Detai
Accounts Receivable, Net (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2016 | Dec. 31, 2015 | |
Accounts Receivable, Net | ||
Advance cash payments received from third parties to mitigate credit risk | $ 52 | $ 88 |
Standby letters of credit | $ 26 | $ 36 |
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date | 30 days | 30 days |
Allowance for doubtful accounts receivable | $ 4 | $ 4 |
Inventory, Linefill and Base 33
Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($)$ / bbl$ / McfMcfbbl | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($)$ / bbl$ / McfMcfbbl | |
Inventory by category | |||
Inventory | $ 877 | $ 916 | |
Linefill and base gas | 899 | 898 | |
Long-term inventory | 112 | 129 | |
Total | 1,888 | 1,943 | |
Inventory-related disclosures | |||
Charge related to the write-down of inventory | 3 | $ 24 | |
Crude oil | |||
Inventory by category | |||
Inventory | 711 | 608 | |
Linefill and base gas | 711 | 713 | |
Long-term inventory | $ 92 | $ 106 | |
Inventory, Volumes (in barrels or in Mcf) | bbl | 21,073 | 16,345 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 12,060 | 12,298 | |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 3,333 | 3,417 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 33.74 | 37.20 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 58.96 | 57.98 | |
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 27.60 | 31.02 | |
NGL | |||
Inventory by category | |||
Inventory | $ 102 | $ 218 | |
Linefill and base gas | 47 | 44 | |
Long-term inventory | $ 20 | $ 23 | |
Inventory, Volumes (in barrels or in Mcf) | bbl | 6,512 | 13,907 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl | 1,348 | 1,348 | |
Long-term inventory, Volumes (in barrels or in Mcf) | bbl | 1,652 | 1,652 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 15.66 | 15.68 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl | 34.87 | 32.64 | |
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl | 12.11 | 13.92 | |
Natural gas | |||
Inventory by category | |||
Inventory | $ 34 | $ 53 | |
Linefill and base gas | $ 141 | $ 141 | |
Inventory, Volumes (in barrels or in Mcf) | Mcf | 17,150 | 22,080 | |
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf | 30,812 | 30,812 | |
Inventory, Price/Unit of measure (in dollars per unit) | $ / Mcf | 1.98 | 2.40 | |
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf | 4.58 | 4.58 | |
Other | |||
Inventory by category | |||
Inventory | $ 30 | $ 37 |
Debt - Components (Details)
Debt - Components (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Short-term debt: | ||
Total short-term debt | $ 715 | $ 999 |
Long-term debt: | ||
Senior notes, net of unamortized discount and debt issuance costs of $74 and $77, respectively | 9,126 | 9,698 |
Noncurrent portion of other long-term debt | 27 | 677 |
Total long-term debt | 9,153 | 10,375 |
Total debt | 9,868 | 11,374 |
Senior notes | ||
Long-term debt: | ||
Unamortized discounts and debt issuance costs | 74 | 77 |
Senior notes, net of unamortized discount and debt issuance costs of $74 and $77, respectively | 9,126 | 9,698 |
5.88% senior notes due August 2016 | ||
Short-term debt: | ||
Current portion of long-term notes and other debt | $ 175 | |
Long-term debt: | ||
Debt instrument, interest rate (as a percent) | 5.88% | |
6.13% senior notes due January 2017 | ||
Short-term debt: | ||
Current portion of long-term notes and other debt | $ 400 | |
Long-term debt: | ||
Debt instrument, interest rate (as a percent) | 6.13% | |
Other | ||
Short-term debt: | ||
Current portion of long-term notes and other debt | $ 3 | 3 |
Long-term debt: | ||
Noncurrent portion of other long-term debt | 4 | 5 |
Commercial paper program | ||
Short-term debt: | ||
Short-term notes and borrowings | $ 137 | $ 696 |
Weighted average interest rate, short-term (as a percent) | 0.90% | 1.10% |
Long-term debt: | ||
Noncurrent portion of other long-term debt | $ 23 | $ 672 |
Weighted average interest rate, long-term (as a percent) | 0.90% | 1.10% |
Senior secured hedged inventory facility | ||
Short-term debt: | ||
Short-term notes and borrowings | $ 300 | |
Weighted average interest rate, short-term (as a percent) | 1.40% |
Debt - Fair Value, Activity, Le
Debt - Fair Value, Activity, Letters of Credit (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Credit facilities and commercial paper program | |||
Debt | |||
Total borrowings | $ 10,800 | $ 7,000 | |
Total repayments | 12,300 | $ 7,700 | |
Letters of credit | |||
Debt | |||
Outstanding letters of credit | 45 | $ 46 | |
Senior notes | |||
Debt | |||
Debt instrument face value | 9,800 | 9,800 | |
Senior notes | Level 2 | |||
Debt | |||
Debt instrument fair value | $ 9,000 | $ 8,600 |
Partners' Capital and Distrib36
Partners' Capital and Distributions - Units Outstanding (Details) - shares | 1 Months Ended | 3 Months Ended | |
Jan. 31, 2016 | Mar. 31, 2016 | Mar. 31, 2015 | |
Series A Preferred Units | |||
Activity for preferred units and common units | |||
Outstanding, end of period | 61,030,127 | ||
Series A Preferred Units | Limited Partners | |||
Activity for preferred units and common units | |||
Sale of Series A preferred units | 61,000,000 | ||
Series A Preferred Units | Limited Partners | Partners' Capital Excluding Noncontrolling Interests | |||
Activity for preferred units and common units | |||
Sale of Series A preferred units | 61,030,127 | ||
Outstanding, end of period | 61,030,127 | ||
Common Units | |||
Activity for preferred units and common units | |||
Outstanding, beginning of period | 397,727,624 | 397,727,624 | |
Outstanding, end of period | 397,730,991 | ||
Common Units | Limited Partners | Partners' Capital Excluding Noncontrolling Interests | |||
Activity for preferred units and common units | |||
Outstanding, beginning of period | 397,727,624 | 397,727,624 | 375,107,793 |
Issuance of common units under LTIP | 3,367 | ||
Sale of common units | 22,133,904 | ||
Outstanding, end of period | 397,730,991 | 397,241,697 |
Partners' Capital and Distrib37
Partners' Capital and Distributions - Preferred Unit Offering (Details) - Series A Preferred Units - Limited Partners shares in Millions | 1 Months Ended | 3 Months Ended |
Jan. 31, 2016$ / sharesshares | Mar. 31, 2016item$ / shares | |
Partners Capital and Distributions | ||
Sale of Series A preferred units (in units) | shares | 61 | |
Cash purchase price (in dollars per unit) | $ 26.25 | |
Annual rate of distributions (as a percent) | 8.00% | |
Annualized distribution rate (in dollars per unit) | $ 2.10 | |
Distribution percentage for general partner interest | 2.00% | |
Preferred unit conversion ratio | 1 | |
Common unit closing price as a percentage of Issue Price, over which the entity has conversion option | 150.00% | |
Period for closing price of common units to be above threshold, to trigger conversion option | 20 days | |
Preferred Distribution Rate Reset Option | ||
Partners Capital and Distributions | ||
Period after fifth and subsequent anniversaries of issuance for distribution rate reset election option | 30 days | |
Number of distribution rate reset elections allowed | item | 1 | |
Basis spread on variable rate (as a percent) | 5.85% | |
Period after sixth anniversary of issuance, after which units may be redeemed if distribution rate has been reset | 30 days | |
Value of common units if exchanged for redemption of preferred units, as a percentage of volume-weighted average price | 95.00% | |
Redemption price as a percentage of Issue Price | 110.00% |
Partners' Capital and Distrib38
Partners' Capital and Distributions - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | May. 13, 2016 | Apr. 07, 2016 | Feb. 12, 2016 | Mar. 31, 2016 | Mar. 31, 2015 |
Partners Capital and Distributions | |||||
Total distributions paid | $ 434 | $ 391 | |||
Fourth Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distribution declared, date | Jan. 12, 2016 | ||||
Distribution payment date | Feb. 12, 2016 | ||||
Forecast | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distribution payment date | May 13, 2016 | ||||
Subsequent Event | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distribution declared, date | Apr. 7, 2016 | ||||
Unitholders of record, date | Apr. 29, 2016 | ||||
Partners' Capital Excluding Noncontrolling Interests | |||||
Partners Capital and Distributions | |||||
Total distributions paid | $ 433 | $ 390 | |||
Partners' Capital Excluding Noncontrolling Interests | Cash Distributions | Fourth Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions paid to General Partner | $ 155 | ||||
Total distributions paid | $ 433 | ||||
Partners' Capital Excluding Noncontrolling Interests | Cash Distributions | Forecast | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions paid to General Partner | $ 155 | ||||
Total distributions paid | 433 | ||||
Common Units | Cash Distributions | Fourth Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions per common unit, paid (in dollars per unit) | $ 0.70 | ||||
Common Units | Cash Distributions | Subsequent Event | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions per common unit, declared (in dollars per unit) | $ 0.70 | ||||
Common Units | Partners' Capital Excluding Noncontrolling Interests | Cash Distributions | Fourth Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions paid to Unitholders | $ 278 | ||||
Common Units | Partners' Capital Excluding Noncontrolling Interests | Cash Distributions | Forecast | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions paid to Unitholders | 278 | ||||
Series A Preferred Units | Partners' Capital Excluding Noncontrolling Interests | In-Kind Distributions | Forecast | First Quarter Distribution | |||||
Partners Capital and Distributions | |||||
Distributions paid to Unitholders | $ 23 | ||||
Distribution of units in lieu of cash (in units) | 858,439 |
Partners' Capital and Distrib39
Partners' Capital and Distributions - Noncontrolling Interests (Details) | Mar. 31, 2016 |
SLC Pipeline LLC | |
Partners Capital and Distributions | |
Noncontrolling interests in subsidiaries (as a percent) | 25.00% |
Derivatives and Risk Manageme40
Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions | 3 Months Ended |
Mar. 31, 2016bbl / dMWhMcfbbl | |
Net long position associated with crude oil purchases | |
Commodity Price Risk Hedging: | |
Average derivative positions notional amount per day (in barrels) | bbl / d | 146,300 |
Derivative position notional amount (in barrels or Mcf) | 4.4 |
Net short time spread position hedging anticipated crude oil lease gathering purchases | |
Commodity Price Risk Hedging: | |
Average derivative positions notional amount per day (in barrels) | bbl / d | 10,000 |
Derivative position notional amount (in barrels or Mcf) | 4.3 |
Crude oil grade spread positions | |
Commodity Price Risk Hedging: | |
Average derivative positions notional amount per day (in barrels) | bbl / d | 2,600 |
Derivative position notional amount (in barrels or Mcf) | 1.2 |
Net short position related to anticipated sales of natural gas inventory and base gas requirements | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | Mcf | 13.9 |
Net short position related to anticipated net sales of crude oil and NGL inventory | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 25.8 |
PLA crude oil long call option position | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 1.4 |
Long natural gas position for natural gas purchases | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | Mcf | 14 |
Short propane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 2.7 |
Short butane position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 0.8 |
Short WTI position related to subsequent sale of products | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in barrels or Mcf) | 0.3 |
Long power position for power supply requirements | |
Commodity Price Risk Hedging: | |
Derivative position notional amount (in megawatt hours) | MWh | 0.4 |
Derivatives and Risk Manageme41
Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) $ in Millions | Mar. 31, 2016USD ($)contract | Dec. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Interest Rate Risk Hedging | ||||
Net deferred gains/(losses) included in AOCI | $ (963) | $ (1,081) | $ (843) | $ (467) |
Interest Rate Derivatives | ||||
Interest Rate Risk Hedging | ||||
Net deferred gains/(losses) included in AOCI | $ (270) | |||
8 forward starting interest rate swaps (30-year), one | Cash flow hedge | ||||
Interest Rate Risk Hedging | ||||
Number of interest rate derivatives (in contracts) | contract | 8 | |||
Notional amount of derivatives | $ 200 | |||
Average rate locked (as a percent) | 3.06% | |||
8 forward starting interest rate swaps (30-year), two | Cash flow hedge | ||||
Interest Rate Risk Hedging | ||||
Number of interest rate derivatives (in contracts) | contract | 8 | |||
Notional amount of derivatives | $ 200 | |||
Average rate locked (as a percent) | 3.14% | |||
8 forward starting interest rate swaps (30-year), three | Cash flow hedge | ||||
Interest Rate Risk Hedging | ||||
Number of interest rate derivatives (in contracts) | contract | 8 | |||
Notional amount of derivatives | $ 200 | |||
Average rate locked (as a percent) | 3.20% | |||
8 forward starting interest rate swaps (30-year), four | Cash flow hedge | ||||
Interest Rate Risk Hedging | ||||
Number of interest rate derivatives (in contracts) | contract | 8 | |||
Notional amount of derivatives | $ 200 | |||
Average rate locked (as a percent) | 2.83% |
Derivatives and Risk Manageme42
Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) CAD in Millions, $ in Millions | Mar. 31, 2016USD ($)CAD / $ | Mar. 31, 2016CADCAD / $ |
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.30 maturing in 2016 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | $ 147 | CAD 191 |
Average exchange rate | 1.30 | 1.30 |
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.33 maturing in 2016 | ||
Currency Exchange Rate Risk Hedging: | ||
Notional amount of derivatives | $ 228 | CAD 302 |
Average exchange rate | 1.33 | 1.33 |
Derivatives and Risk Manageme43
Derivatives and Risk Management Activities - Embedded Derivatives (Details) $ in Millions | Mar. 31, 2016USD ($) |
Preferred Distribution Rate Reset Option | Series A Preferred Units | |
Embedded Derivatives | |
Fair value of derivative liability | $ 60 |
Derivatives and Risk Manageme44
Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | $ 36 | $ (47) |
Commodity Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 32 | (27) |
Commodity Derivatives | Transportation segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 2 | 2 |
Commodity Derivatives | Field operating costs | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | (2) | (4) |
Interest Rate Derivatives | Interest expense, net | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | (2) | (1) |
Foreign Currency Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 6 | (17) |
Derivatives in Hedging Relationships | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | (1) | 6 |
Derivatives in Hedging Relationships | Commodity Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 1 | 7 |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense, net | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | (2) | (1) |
Derivatives Not Designated as a Hedge | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 37 | (53) |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 31 | (34) |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Transportation segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | 2 | 2 |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | (2) | (4) |
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues | ||
Impact of derivative activities recognized in earnings | ||
Total Gain/(Loss) on Derivatives Recognized in Net Income | $ 6 | $ (17) |
Derivatives and Risk Manageme45
Derivatives and Risk Management Activities - Assets and Liabilities (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($)contract | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($)contract | |
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | $ 181 | $ 280 | |
Liability Derivatives Fair Value | (294) | (110) | |
Broker payable | 17 | 156 | |
Initial margin | 70 | 91 | |
Variation margin returned | 87 | $ 247 | |
Net loss deferred in AOCI | 292 | ||
Net loss expected to be reclassified to earnings in the next twelve months | 5 | ||
Remaining loss expected to be reclassified to earnings through 2049 | 287 | ||
Net deferred gain/(loss) recognized in AOCI on derivatives | $ (90) | $ (72) | |
Number of outstanding derivatives containing credit-risk related contingent features | contract | 0 | 0 | |
Derivative credit-risk related contingent features | 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 | ||
Commodity Derivatives | |||
Derivative assets and liabilities | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | 3 | ||
Interest Rate Derivatives | |||
Derivative assets and liabilities | |||
Net deferred gain/(loss) recognized in AOCI on derivatives | $ (90) | $ (75) | |
Derivatives in Hedging Relationships | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 3 | $ 5 | |
Liability Derivatives Fair Value | (140) | (52) | |
Derivatives in Hedging Relationships | Commodity Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 3 | 4 | |
Liability Derivatives Fair Value | (2) | (2) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term assets, net | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 1 | ||
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | (41) | (17) | |
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | (97) | (33) | |
Derivatives Not Designated as a Hedge | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 178 | 275 | |
Liability Derivatives Fair Value | (154) | (58) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 170 | 265 | |
Liability Derivatives Fair Value | (78) | (35) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 10 | ||
Liability Derivatives Fair Value | (1) | ||
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 1 | ||
Liability Derivatives Fair Value | (13) | (13) | |
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 2 | ||
Liability Derivatives Fair Value | (3) | (1) | |
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current assets | |||
Derivative assets and liabilities | |||
Asset Derivatives Fair Value | 5 | ||
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | $ (8) | ||
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other long-term liabilities and deferred credits | |||
Derivative assets and liabilities | |||
Liability Derivatives Fair Value | $ (60) |
Derivatives and Risk Manageme46
Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative Asset Positions | ||
Gross Position - Asset | $ 181 | $ 280 |
Netting Adjustment | (83) | (38) |
Cash collateral received | (17) | (156) |
Net Position - Asset | 81 | 86 |
Derivative Liability Positions | ||
Gross Position - Liability | (294) | (110) |
Netting Adjustment | 83 | 38 |
Net Position - Liability | (211) | (72) |
Other current assets | ||
Derivative Asset Positions | ||
Net Position - Asset | 81 | 76 |
Other long-term assets, net | ||
Derivative Asset Positions | ||
Net Position - Asset | 10 | |
Other current liabilities | ||
Derivative Liability Positions | ||
Net Position - Liability | (53) | (38) |
Other long-term liabilities and deferred credits | ||
Derivative Liability Positions | ||
Net Position - Liability | $ (158) | $ (34) |
Derivatives and Risk Manageme47
Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Level 3 | |||
Rollforward of Level 3 Net Asset/(Liability) | |||
Beginning Balance | $ 11 | $ 15 | |
Losses for the period included in earnings | (1) | ||
Settlements | (9) | (12) | |
Derivatives entered into during the period | (60) | 2 | |
Ending Balance | (59) | 5 | |
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period | (1) | $ 2 | |
Recurring Fair Value Measures | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (113) | $ 170 | |
Recurring Fair Value Measures | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 80 | 227 | |
Recurring Fair Value Measures | Interest Rate Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (138) | (49) | |
Recurring Fair Value Measures | Foreign Currency Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 5 | (8) | |
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (60) | ||
Recurring Fair Value Measures | Level 1 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 62 | 126 | |
Recurring Fair Value Measures | Level 1 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 62 | 126 | |
Recurring Fair Value Measures | Level 2 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (116) | 33 | |
Recurring Fair Value Measures | Level 2 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 17 | 90 | |
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (138) | (49) | |
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 5 | (8) | |
Recurring Fair Value Measures | Level 3 | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | (59) | 11 | |
Recurring Fair Value Measures | Level 3 | Commodity Derivatives | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | 1 | $ 11 | |
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option | |||
Recurring Fair Value Measurements | |||
Net derivative asset/(liability) | $ (60) |
Related Party Transactions (Det
Related Party Transactions (Details) - Oxy - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Related Party Transactions | |||
Related party ownership of general partner interest (as a percent) | 13.00% | ||
Revenues | $ 112 | $ 176 | |
Purchases and related costs | $ 104 | ||
Purchases and related costs net credit | (46) | ||
Trade accounts receivable and other receivables | 474 | $ 405 | |
Accounts payable | $ 431 | $ 363 |
Commitments and Contingencies -
Commitments and Contingencies - Legal, Environmental or Regulatory (Details) | Jan. 06, 2016USD ($)item | Jul. 10, 2015bbl | Jan. 01, 2015bbl | May. 31, 2015bbl | Mar. 31, 2016USD ($)lawsuit | Mar. 31, 2016USD ($)lawsuit | Dec. 31, 2015USD ($) | Apr. 30, 2015item |
Legal, Environmental or Regulatory Matters | ||||||||
Estimated undiscounted reserve for environmental liabilities | $ 176,000,000 | $ 176,000,000 | $ 185,000,000 | |||||
Estimated undiscounted reserve for environmental liabilities, short-term | 69,000,000 | 69,000,000 | 81,000,000 | |||||
Estimated undiscounted reserve for environmental liabilities, long-term | 107,000,000 | 107,000,000 | 104,000,000 | |||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 81,000,000 | 81,000,000 | $ 161,000,000 | |||||
Line 901 Incident | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Aggregate total estimated costs | 269,000,000 | 269,000,000 | ||||||
Estimated undiscounted reserve for environmental liabilities | 104,000,000 | 104,000,000 | ||||||
Recoveries from insurance carriers | 112,000,000 | |||||||
Total release costs probable of recovery | 186,000,000 | 186,000,000 | ||||||
Amounts probable of recovery under insurance and from third parties under indemnification agreements | 74,000,000 | 74,000,000 | ||||||
Fines or penalties assessed | 0 | $ 0 | ||||||
Line 901 Incident | Class Action Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 8 | |||||||
Number of cases consolidated into a single proceeding | lawsuit | 7 | |||||||
Line 901 Incident | Securities Law Class Action Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 2 | |||||||
Line 901 Incident | Unitholder Derivative Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 3 | |||||||
Line 901 Incident | Production of Books And Records Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 2 | |||||||
Line 901 Incident | Worst Case Estimate | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated size of release (in barrels) | bbl | 2,935 | |||||||
MP 29 Release | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated size of release (in barrels) | bbl | 100 | |||||||
Fines or penalties assessed | 0 | $ 0 | ||||||
MP 29 Release | Maximum | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Aggregate total estimated costs | $ 10,000,000 | 10,000,000 | ||||||
MP 29 Release | Class Action Lawsuits | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of cases filed during the period | lawsuit | 1 | |||||||
In the Matter of Bakersfield Crude Terminal LLC et al | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of alleged rule violations | item | 10 | |||||||
Fines or penalties assessed | $ 0 | $ 0 | ||||||
Mesa to Basin Pipeline | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Estimated size of release (in barrels) | bbl | 500 | |||||||
Mesa to Basin Pipeline | PHMSA | ||||||||
Legal, Environmental or Regulatory Matters | ||||||||
Number of occasions of alleged failure to carry out damage prevention program and other procedures | item | 4 | |||||||
Fines or penalties recommended | $ 190,000 |
Operating Segments - Segment Fi
Operating Segments - Segment Financial Data (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2016USD ($)segment | Mar. 31, 2015USD ($) | |
Operating Segments | ||
Operating segments number | segment | 3 | |
Revenues: | ||
Total revenues | $ 4,111 | $ 5,942 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Equity earnings in unconsolidated entities | 47 | 37 |
Segment profit | 443 | 513 |
Maintenance capital | 47 | 50 |
Transportation | ||
Revenues: | ||
Total revenues | 154 | 185 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Equity earnings in unconsolidated entities | 47 | 37 |
Segment profit | 247 | 241 |
Maintenance capital | 35 | 33 |
Facilities | ||
Revenues: | ||
Total revenues | 138 | 125 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Segment profit | 159 | 142 |
Maintenance capital | 9 | 15 |
Supply and Logistics | ||
Revenues: | ||
Total revenues | 3,819 | 5,632 |
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments | ||
Segment profit | 37 | 130 |
Interest expense related to hedged inventory purchases | 2 | 1 |
Maintenance capital | 3 | 2 |
Operating Segments | ||
Revenues: | ||
Total revenues | 4,469 | 6,291 |
Operating Segments | Transportation | ||
Revenues: | ||
Total revenues | 383 | 400 |
Operating Segments | Facilities | ||
Revenues: | ||
Total revenues | 265 | 257 |
Operating Segments | Supply and Logistics | ||
Revenues: | ||
Total revenues | 3,821 | 5,634 |
Intersegment | ||
Revenues: | ||
Total revenues | (358) | (349) |
Intersegment | Transportation | ||
Revenues: | ||
Total revenues | (229) | (215) |
Intersegment | Facilities | ||
Revenues: | ||
Total revenues | (127) | (132) |
Intersegment | Supply and Logistics | ||
Revenues: | ||
Total revenues | $ (2) | $ (2) |
Operating Segments - Reconcilia
Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Reconciliation of segment profit to net income attributable to PAA | ||
Segment profit | $ 443 | $ 513 |
Depreciation and amortization | (114) | (104) |
Interest expense, net | (112) | (105) |
Other income/(expense), net | 5 | (4) |
INCOME BEFORE TAX | 222 | 300 |
Income tax expense | (19) | (16) |
NET INCOME | 203 | 284 |
Net income attributable to noncontrolling interests | (1) | (1) |
NET INCOME ATTRIBUTABLE TO PAA | $ 202 | $ 283 |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Acquisitions (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2016USD ($)item | |
Acquisitions and Dispositions | |
Number of acquisitions completed | item | 1 |
Cash consideration | $ | $ 85 |
Acquisitions and Dispositions53
Acquisitions and Dispositions - Dispositions (Details) - Non-core assets $ in Millions | 3 Months Ended |
Mar. 31, 2016USD ($) | |
Held for sale | Depreciation and amortization | |
Dispositions | |
Impairment losses related to non-core asset sales | $ 50 |
Impairment of goodwill included in disposal group classified as held for sale | 15 |
Held for sale | Other current assets | |
Dispositions | |
Assets classified as held for sale | 120 |
Disposed of by sale | Depreciation and amortization | |
Dispositions | |
Gain on sales of non-core assets | $ 56 |