Document and Entity Information
Document and Entity Information Document - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 25, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | Breitburn Energy Partners LP | ||
Entity Central Index Key | 1,357,371 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 213,670,116 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 1 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash | $ 10,464 | $ 12,628 |
Accounts and other receivables, net (note 2) | 128,589 | 166,436 |
Derivative instruments (note 4) | 439,627 | 408,151 |
Related party receivables (note 5) | 2,274 | 2,462 |
Inventory | 926 | 3,727 |
Prepaid expenses | 6,447 | 7,304 |
Total current assets | 588,327 | 600,708 |
Equity investments | 6,567 | 6,463 |
Property, plant and equipment | ||
Oil and natural gas properties (note 3) | 7,898,117 | 7,736,409 |
Other property, plant and equipment (note 3) | 188,795 | 60,533 |
Property, plant and equipment, gross | 8,086,912 | 7,796,942 |
Accumulated depletion, depreciation and impairment (note 6) | (4,154,030) | (1,342,741) |
Net property, plant and equipment | 3,932,882 | 6,454,201 |
Other long-term assets | ||
Goodwill | 0 | 92,024 |
Derivative instruments (note 4) | 226,764 | 319,560 |
Other long-term assets (note 8) | 117,872 | 165,378 |
Total assets | 4,872,412 | 7,638,334 |
Current liabilities: | ||
Accounts payable | 50,412 | 129,270 |
Current portion of long-term debt (note 9) | 154,000 | 105,000 |
Derivative instruments (note 4) | 4,462 | 5,457 |
Distributions payable | 733 | 733 |
Current asset retirement obligation | 2,341 | 4,948 |
Revenue and royalties payable | 35,462 | 40,452 |
Wages and salaries payable | 21,654 | 22,322 |
Accrued interest payable | 19,517 | 20,672 |
Production and property taxes payable | 24,292 | 25,207 |
Other current liabilities | 5,133 | 7,495 |
Total current liabilities | 318,006 | 361,556 |
Credit facility (note 9) | 1,075,000 | 2,089,500 |
Senior notes, net (note 9) | 1,789,219 | 1,156,560 |
Other long-term debt (note 9) | 2,938 | 1,100 |
Total long-term debt (note 9) | 2,867,157 | 3,247,160 |
Deferred income taxes (note 11) | 3,844 | 2,575 |
Asset retirement obligation (note 12) | 252,037 | 233,463 |
Derivative instruments (note 4) | 255 | 2,269 |
Other long-term liabilities | 25,218 | 25,135 |
Total liabilities | $ 3,466,517 | $ 3,872,158 |
Commitments and contingencies (note 14) | ||
Equity: | ||
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at December 31, 2015 and December 31, 2014 (note 15) | $ 193,215 | $ 193,215 |
Series B perpetual convertible preferred units, 48.8 million and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively (note 15) | 353,471 | 0 |
Common units, 213.5 million and 210.9 million units issued and outstanding at December 31, 2015 and December 31, 2014, respectively (note 15) | 852,114 | 3,566,468 |
Accumulated other comprehensive loss (note 16) | (229) | (392) |
Total partners' equity | 1,398,571 | 3,759,291 |
Noncontrolling interest (note 17) | 7,324 | 6,885 |
Total equity | 1,405,895 | 3,766,176 |
Total liabilities and equity | $ 4,872,412 | $ 7,638,334 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) - shares | Dec. 31, 2015 | Dec. 31, 2014 |
Series B Perpetual Convertible Preferred Units, Outstanding | 48,800,000 | 0 |
Common units | 213,500,000 | 210,900,000 |
Preferred Units [Member] | ||
Series A Cumulative redeemable preferred units | 8,000,000 | 8,000,000 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues and other income items | |||
Oil, natural gas and natural gas liquid sales | $ 645,272 | $ 855,820 | $ 660,665 |
Gain (loss) on commodity derivative instruments, net (note 4) | 438,614 | 566,533 | (29,182) |
Other revenue, net | 24,829 | 7,616 | 3,175 |
Total revenues and other income items | 1,108,715 | 1,429,969 | 634,658 |
Operating costs and expenses: | |||
Operating costs | 455,189 | 355,681 | 262,822 |
Depletion, depreciation and amortization | 460,047 | 291,709 | 216,495 |
Impairments of oil and natural gas properties (note 6) | 2,377,615 | 149,000 | 54,373 |
Impairment of goodwill (note 6) | 95,947 | 0 | 0 |
General and administrative expenses | 98,999 | 86,949 | 58,707 |
Restructuring costs (note 21) | 6,364 | 0 | 0 |
(Gain) loss on sale of assets (note 3) | (8,864) | 663 | (2,015) |
Total operating costs and expenses | 3,485,297 | 884,002 | 590,382 |
Operating (loss) income | (2,376,582) | 545,967 | 44,276 |
Interest expense, net of capitalized interest (note 9) | 203,027 | 126,960 | 87,067 |
Loss (gain) on interest rate swaps (note 4) | 2,691 | (490) | 0 |
Other expense (income), net | (814) | (1,746) | (25) |
(Loss) income before taxes | (2,581,486) | 421,243 | (42,766) |
Income tax expense (benefit) (note 11) | 1,527 | (73) | 905 |
Net (loss) income | (2,583,013) | 421,316 | (43,671) |
Less: Net income (loss) attributable to noncontrolling interest (note 17) | 326 | (17) | 0 |
Net (loss) income attributable to the partnership | (2,583,339) | 421,333 | (43,671) |
Less: Distributions to Series A preferred unitholders | 16,500 | 10,083 | 0 |
Less: Non-cash distributions to Series B preferred unitholders | 20,817 | 0 | 0 |
Less: Net income (loss) attributable to participating units | 0 | 5,348 | 0 |
Less: Distributions on participating units in excess of earnings | 1,731 | 0 | 0 |
Net (loss) income used to calculate basic and diluted net (loss) income per unit | $ (2,622,387) | $ 405,902 | $ (43,671) |
Basic net (loss) income per unit (note 15) | $ (12.39) | $ 3.04 | $ (0.43) |
Diluted net (loss) income per unit (note 15) | $ (12.39) | $ 3.02 | $ (0.43) |
Weighted Average Number of Shares Outstanding, Basic | 211,575 | 133,451 | 101,604 |
Weighted Average Number of Shares Outstanding, Diluted | 211,575 | 134,206 | 101,604 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Statement of Comprehensive Income [Abstract] | ||||
Net (loss) income | $ (2,583,013) | $ 421,316 | $ (43,671) | |
Other comprehensive income (loss), net of tax: | ||||
Change in fair value of available-for-sale securities | [1] | (402) | (189) | 0 |
Pension and post-retirement benefits actuarial loss | [2] | 677 | (473) | 0 |
Total other comprehensive income (loss), net of tax | 275 | (662) | 0 | |
Total comprehensive (loss) income | (2,582,738) | 420,654 | (43,671) | |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 438 | (287) | 0 | |
Comprehensive (loss) income attributable to the partnership | $ (2,583,176) | $ 420,941 | $ (43,671) | |
[1] | Net of income taxes of $0.3 million and $0.1 million for the years ended December 31, 2015 and 2014, respectively. | |||
[2] | Net of income tax (benefit) expense of $(0.1) million and $0.2 million for the years ended December 31, 2015 and 2014, respectively. |
Consolidated Statement of Comp6
Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Comprehensive Income [Abstract] | ||
Tax on change in fair value of available-for-sale securities | $ 0.3 | $ 0.1 |
Tax on pension and post-retirement benefits actuarial loss | $ (0.1) | $ 0.2 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Cash Flows [Abstract] | |||
Net (loss) income | $ (2,583,013) | $ 421,316 | $ (43,671) |
Adjustments to reconcile to cash flow from operating activities: | |||
Depletion, depreciation and amortization | 460,047 | 291,709 | 216,495 |
Impairments of oil and natural gas properties | 2,377,615 | 149,000 | 54,373 |
Impairment of goodwill (note 6) | 95,947 | 0 | 0 |
Unit-based compensation expense | 26,805 | 23,387 | 19,955 |
(Gain) loss on derivative instruments | (435,923) | (567,024) | 29,182 |
Derivative instrument settlement receipts | 494,234 | 26,806 | 8,083 |
Settlement payments on terminated derivative instruments | (104) | 178 | (55) |
Income from equity affiliates, net | 1,269 | (174) | 262 |
(Gain) loss on sale of assets | (8,864) | 663 | (2,015) |
Other | 16,142 | 6,204 | 5,163 |
Changes in net assets and liabilities: | |||
Accounts receivable and other assets | 35,367 | 41,754 | (29,322) |
Inventory | 2,801 | 163 | (804) |
Net change in related party receivables and payables | 188 | 142 | (1,191) |
Accounts payable and other liabilities | (45,806) | (36,369) | 711 |
Net cash provided by operating activities | 436,705 | 357,755 | 257,166 |
Cash flows from investing activities | |||
Property acquisitions, net of cash acquired (note 3) | (18,201) | (401,465) | (1,175,817) |
Capital expenditures | (269,350) | (417,755) | (266,308) |
Proceeds from sale of assets | 14,547 | 499 | 2,981 |
Proceeds from sale of available-for-sale securities | 3,875 | 0 | 0 |
Purchases of available-for-sale securities | (4,021) | 0 | 0 |
Other | (853) | (18,283) | (26,661) |
Net cash used in investing activities | (274,003) | (837,004) | (1,465,805) |
Cash flows from financing activities | |||
Proceeds from issuance of preferred units, net | 337,238 | 193,215 | 0 |
Proceeds from issuance of common units, net | 3,008 | 277,613 | 618,013 |
Distributions to preferred unitholders | (16,502) | (9,350) | 0 |
Distributions to common unitholders | (126,188) | (264,585) | (186,868) |
Proceeds from issuance of long-term debt, net | 1,378,338 | 2,457,600 | 2,276,000 |
Repayments of long-term debt | (1,711,500) | (1,785,000) | (1,487,000) |
Senior note redemption | 0 | (352,531) | 0 |
Change in bank overdraft | 11 | (2,434) | 2,013 |
Debt issuance costs | (29,271) | (25,109) | (15,568) |
Net cash (used in) provided by financing activities | (164,866) | 489,419 | 1,206,590 |
(Decrease) increase in cash | (2,164) | 10,170 | (2,049) |
Cash beginning of period | 12,628 | 2,458 | 4,507 |
Cash end of period | $ 10,464 | $ 12,628 | $ 2,458 |
Consolidated Statements of Part
Consolidated Statements of Partners' Equity shares in Thousands, CommonUnit in Thousands, $ in Thousands | USD ($)shares | Preferred Units [Member]USD ($)CommonUnitunitsshares | Preferred Units B [Member]USD ($)CommonUnitunitsshares | Common Units [Member]USD ($)CommonUnitshares | Accumulated Other Comprehensive Income (Loss)I [Member]USD ($) |
Units, beginning balance at Dec. 31, 2012 | shares | 0 | 0 | 84,668 | ||
Partners' Equity, beginning balance at Dec. 31, 2012 | $ 1,589,536 | $ 0 | $ 0 | $ 1,589,536 | $ 0 |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Partners' Capital Account, Units, Sold in Public Offering | shares | 0 | 33,925 | |||
Partners' Capital Account, Public Sale of Units | $ 617,752 | 0 | 0 | $ 617,752 | 0 |
Distributions on Common Units | (183,594) | $ 0 | $ 0 | $ (183,594) | 0 |
Common Units issued under incentive plans (shares) | 0 | 0 | 577 | ||
Units Issued Under Incentive Plans | 12,421 | $ 0 | $ 0 | $ 12,421 | 0 |
Distributions paid on unissued units under incentive plans | (3,274) | 0 | 0 | (3,274) | 0 |
Partners' Capital Account, Unit-based Compensation | 650 | 0 | 0 | 650 | 0 |
Net (loss) income attributable to the partnership | (43,671) | $ 0 | $ 0 | $ (43,671) | 0 |
Units, ending balance at Dec. 31, 2013 | shares | 0 | 0 | 119,170 | ||
Partners' Equity, ending balance at Dec. 31, 2013 | 1,989,820 | $ 0 | $ 0 | $ 1,989,820 | 0 |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Partners' Capital Account, Units, Sold in Public Offering | shares | 8,000 | 0 | 15,272 | ||
Partners' Capital Account, Public Sale of Units | 277,605 | $ 0 | $ 0 | $ 277,605 | 0 |
Sale of Common Units | 193,215 | 193,215 | 0 | 0 | 0 |
Dividends, Preferred Stock | 10,083 | (10,083) | 0 | 0 | 0 |
Distributions on Common Units | 260,958 | $ 0 | $ 0 | $ (260,958) | 0 |
Common Units issued for acquisitions, Units | shares | 0 | 0 | 75,837 | ||
Partners' Capital Account, Acquisitions | 1,131,146 | $ 0 | $ 0 | $ 1,131,146 | 0 |
Common Units issued under incentive plans (shares) | CommonUnit | 0 | 0 | 615 | ||
Units Issued Under Incentive Plans | 17,985 | $ 0 | $ 0 | $ 17,985 | 0 |
Distributions paid on unissued units under incentive plans | 3,626 | 0 | 0 | (3,626) | 0 |
Partners' Capital Account, Unit-based Compensation | 3,246 | 0 | 0 | 3,246 | 0 |
Net (loss) income attributable to the partnership | 421,333 | 10,083 | 0 | 411,250 | 0 |
Other Comprehensive Income (Loss), Net of Tax | $ (392) | $ 0 | $ 0 | $ 0 | (392) |
Units, ending balance at Dec. 31, 2014 | shares | 210,900 | 8,000 | 0 | 210,894 | |
Partners' Equity, ending balance at Dec. 31, 2014 | $ 3,759,291 | $ 193,215 | $ 0 | $ 3,566,468 | (392) |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Partners' Capital Account, Units, Sold in Private Placement | shares | 0 | 46,667 | 0 | ||
Partners' Capital Account, Private Placement of Units | 337,238 | $ 0 | $ 337,238 | $ 0 | 0 |
Partners' Capital Account, Units, Sold in Public Offering | shares | 0 | 0 | 544 | ||
Partners' Capital Account, Public Sale of Units | $ 3,115 | $ 0 | $ 0 | $ 3,115 | 0 |
Stock Dividends, Shares | shares | 0 | 0 | 448 | ||
Preferred Stock Dividends, Shares | shares | 0 | 0 | 2,164 | ||
Dividends, Preferred Stock, Stock | $ 0 | $ 0 | $ 0 | 0 | |
Dividends, Preferred Stock | 16,500 | $ (16,500) | 0 | 0 | 0 |
Dividends | (1,225) | 0 | (1,225) | 0 | 0 |
Dividends, Stock | 0 | (3,359) | 3,359 | 0 | |
Distributions on Common Units | 123,217 | $ 0 | $ 0 | $ (123,217) | 0 |
Common Units issued under incentive plans (shares) | CommonUnit | 0 | 0 | 1,595 | ||
Units Issued Under Incentive Plans | 28,500 | $ 0 | $ 0 | $ 28,500 | 0 |
Distributions paid on unissued units under incentive plans | 2,971 | 0 | 0 | (2,971) | 0 |
Partners' Capital Account, Unit-based Compensation | (2,484) | 0 | 0 | (2,484) | 0 |
Net (loss) income attributable to the partnership | (2,583,339) | 16,500 | 20,817 | (2,620,656) | 0 |
Other Comprehensive Income (Loss), Net of Tax | $ 163 | $ 0 | $ 0 | $ 0 | 163 |
Units, ending balance at Dec. 31, 2015 | shares | 213,500 | 8,000 | 48,831 | 213,481 | |
Partners' Equity, ending balance at Dec. 31, 2015 | $ 1,398,571 | $ 193,215 | $ 353,471 | $ 852,114 | $ (229) |
Organization
Organization | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Organization We are a Delaware limited partnership formed on March 23, 2006. Our initial public offering was in October 2006. Pacific Coast Energy Company LP (“PCEC”), formerly Breitburn Energy Company LP, is our Predecessor. Our general partner is Breitburn GP LLC, a wholly-owned Delaware limited liability company (the “General Partner”), also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly-owned subsidiary, Breitburn Operating LP, (“BOLP”), BOLP’s general partner, Breitburn Operating GP LLC (“BOGP”), and through BOLP’s operating subsidiaries. On November 19, 2014 , we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of July 23, 2014 (the “Merger Agreement”) with QR Energy, LP, a Delaware limited partnership (“QRE”). Pursuant to the terms of the Merger Agreement, QRE merged with a subsidiary of the Partnership, with QRE continuing as the surviving entity and as a direct wholly owned subsidiary of the Partnership (the “QRE Merger”). Immediately thereafter, the Partnership transferred 100% of the limited partner interests of QRE to BOLP. In connection with the QRE Merger, we acquired a controlling interest in East Texas Salt Water Disposal Company (“ETSWDC”), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields. See Note 3 for more information. Our wholly owned subsidiary, Breitburn Management Company LLC (“Breitburn Management”), manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 5 for information regarding our relationship with Breitburn Management. Our wholly-owned subsidiary, Breitburn Finance Corporation (“Breitburn Finance”), was incorporated on June 1, 2009 under the laws of the State of Delaware. Breitburn Finance has no assets or liabilities, and its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly-owned subsidiary, Breitburn Collingwood Utica LLC (“Breitburn Utica”), holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facility. We own 100% of our General Partner, BOLP, Breitburn Management, Breitburn Finance and Breitburn Utica. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Principles of consolidation and basis of presentation The consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2015 and 2014 . These financial statements also include the results of our operations, our changes in comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2015 , 2014 , and 2013 . These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In addition, we assume realization of assets and settlement of liabilities in the normal course of business. We recognized net loss attributable to the partnership of $2.58 billion and cash provided by operations was $436.7 million for the year ended December 31, 2015 and had cash on hand of $10.5 million at December 31, 2015 . As of December 31, 2015, we had approximately $1.2 billion in borrowings under our credit facility, including $154 million classified as a current liability, and $25.8 million in letters of credit outstanding. Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria (see Note 9 for further discussion of our borrowing base). The borrowing base at December 31, 2015 was $1.8 billion and the next semi-annual redetermination is scheduled for April 2016. Based upon current commodity prices and other factors at the time of future redeterminations, we expect our borrowing base to be significantly decreased. Without a waiver from our lenders, our credit facility currently provides that if the borrowing base is reduced below our current outstanding borrowings, we are required to repay the deficiency in five equal monthly installments. Although our lenders have the discretion to redetermine the borrowing base below our current outstanding borrowings, we do not expect that to occur in April 2016. However, if commodity prices remain depressed or further decline, we expect our borrowing base to be reduced again at the subsequent borrowing base redetermination in October 2016, which could further impact and limit our liquidity. We believe our existing cash resources and hedge positions should provide us with sufficient funds to meet our expected working capital needs for 2016, assuming that our borrowing base is redetermined above our current outstanding borrowings. Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our credit facility will not reduce the borrowing base to an amount below our current outstanding borrowings in April or at the October 2016 redetermination or that our liquidity requirements will continue to be satisfied, given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the steep decline in commodity prices and the trading prices of our debt and equity securities, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in many cases, ceased to provide any new funding. We expect that we will take other actions to raise funds to repay debt, such as selling non-core assets or restructuring derivative contracts. As a result of both the low commodity price environment and our substantial debt burden, our liquidity will remain limited absent a material improvement in oil and natural gas prices or a refinancing or restructuring of our balance sheet debt. We may engage financial and legal advisors to advise our management and our Board of Directors regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our leverage and liquidity issues. We are also focused on cost reductions and the identification of non-core assets for potential sale. We cannot give any assurances that any of these efforts will be possible on acceptable terms or will be successful or result in actual cost reductions or additional cash flows or the timing of any such potential results. Use of estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, debt subject to acceleration, fair value of derivative instruments, unit-based compensation, pension and post-retirement obligations, future cash flow from oil, NGL and natural gas properties and oil, NGL and natural gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil, NGL and natural gas properties and goodwill. Business segment information We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas. Cash and cash equivalents We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. Our cash and cash equivalents consist of cash in banks and investments in money market accounts. The majority of cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk. Accounts receivable Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2015 and 2014 , we had an allowance for doubtful accounts receivable of $2.1 million and $1.6 million , respectively. Inventory Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. When using lower of cost or market to value inventory, market is the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2015 and December 31, 2014 and we recognized write-downs of $0.6 million and $1.0 million , respectively. Property, plant and equipment Oil and natural gas properties We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred. We carry out tertiary recovery methods on certain of our oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO 2 , for enhanced oil recovery activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO 2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO 2 recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed. Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years. We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2015 , 2014 and 2013 , interest of $0.2 million , $0.3 million and $0.1 million , respectively, was capitalized and included in our capital expenditures. Non-oil and natural gas assets Buildings and non-oil and gas assets, including property and equipment related to the disposal of salt water at our East Texas fields, are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 25 years. In March 2015, we acquired certain CO 2 producing properties located in Harding County, New Mexico for the purpose of accessing CO 2 reserves for our tertiary activities (“CO 2 Assets”). See Note 3 for more information. The lease acquisition and development costs (tangible and intangible) incurred relating to CO 2 Assets are capitalized. Lease acquisition and any additional development costs are depleted using the units of production method and the tangible equipment are depreciated on a straight-line method over 40 years. Oil and natural gas reserve quantities Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports. Investments Investments consist of debt and equity securities, all of which are classified as available-for-sale and stated at fair value on our consolidated balance sheet. Accordingly, unrecognized changes in fair value and the related deferred tax effect are excluded from earnings and reported as a separate component within our consolidated statement of other comprehensive income. Changes in fair value of securities sold are computed based on the specific identification of the securities sold, and are reclassified from other comprehensive income into earnings (reflected in other expense (income), net on the consolidated statements of operations) in the period sold. Pensions and Other Postretirement Benefits We recognize the overfunded or underfunded status of the pension and postretirement benefit plans as either assets or liabilities on our consolidated balance sheet. A plan’s funded status is the difference between the fair value of the plan assets and the plan’s benefit obligation. The plan’s benefit obligation is based on estimates using management’s best estimate and judgments which includes independent actuarial service assumptions to determine the plan obligation. We record the plan’s cost and income – unrecognized losses and gains, unrecognized prior service costs and credits and transition obligations, if any – in our consolidated statement of other comprehensive income until they are amortized into earnings as a component of benefit costs. Debt issuance costs The costs incurred to obtain financing have been capitalized. Debt issuance costs are charged to interest expense over the term of the related debt instrument. With the implementation of Accounting Standards Update ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs , unamortized debt issuance costs associated with our outstanding Senior Notes (as defined below), which were formerly presented as a component of Other long-term assets, will be shown as a reduction to the carrying liability amount of our Senior Notes. Asset retirement obligations We have significant obligations to plug and abandon oil, natural gas and saltwater disposal wells and related equipment at the end of oil and natural gas production operations or salt water disposal operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. Revenue recognition We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As of December 31, 2015 and 2014 , our natural gas producer imbalance liability was $11.4 million and $11.5 million , respectively, reflected in other long-term liabilities on the consolidated balance sheets. Impairments Long-lived assets and finite lived intangible assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset or finite lived intangible asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset or finite lived intangible asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2% per year. Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the commodity price strip used where applicable. For impairment charges, the associated property’s expected future net cash flows were discounted using a long-term weighted average cost of capital which approximated 10% at December 31, 2015 . Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 6 for a discussion of impairments of oil, NGL and natural gas assets. We account for goodwill in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and charged to impairments. The analysis of the potential impairment of goodwill is a two step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment. Step two of the goodwill impairment test consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment. Equity-based compensation Breitburn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 18. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is part of the general and administrative (“G&A”) expenses line on the consolidated statements of operations. We recognize equity-based compensation costs on a straight line basis over the requisite service periods. Fair market value of financial instruments The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 9 for the fair value of our Senior Notes. Accounting for business combinations We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets acquired and liabilities assumed are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. There was no goodwill recognized for 2015 acquisitions. We recognized $95.9 million of goodwill as part of the final purchase price related to the 2014 QRE Merger, which became fully impaired in 2015. Concentration of credit risk We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility, and we periodically monitor their credit ratings. For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of our crude oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows. Derivatives FASB Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. See Note 4 for detail on our derivative instruments. Income taxes Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided. We have three wholly-owned subsidiaries and a controlling interest in an additional subsidiary that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies. We performed an analysis as of December 31, 2015 and 2014 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. Net income or loss per unit FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Participating securities are not allocated losses in periods where net losses occur. Our 8.25% Series A Cumulative Redeemable Perpetual Preferred Units and 8.0% Series B Perpetual Convertible Preferred Units (collectively, the “Preferred Units”) rank senior to our Common Units with respect to the payment of distributions and, therefore, distributions on Preferred Units are deducted from net income when calculating net income attributable to common unitholders and participating securities. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation. Environmental expenditures We review, on an annual basis and when new information becomes available, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At December 31, 2015 and 2014 , we had $0.6 million and $1.8 million undiscounted environmental liability accrued, respectively, that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. In December 2015, the environmental liability decreased by $1.2 million due to cost reductions to the estimated provision. Accounting Standards In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs . The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively. Early adoption is permitted. The adoption of these standards will not have an impact on our consolidated financial statements, other than balance sheet reclassifications. Under ASU 2015-03, the unamortized debt issuance costs of approximately $37.0 million as of December 31, 2015, associated with our outstanding Senior Notes, which were formerly presented as a component of Other Long Term Assets, will be shown as a reduction to the carrying liability amount of our Senior Notes. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . ASU 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These new requirements become effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. We are assessing the impact that ASU 2014-09 will have on our consolidated financial |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisitions We account for all business combinations using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustments to provisional accounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date prior to concluding on the final purchase price of an acquisition. Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital. We also periodically employ third party valuation firms to assist in the valuation of complex facilities, including pipelines, gathering lines and processing facilities. We conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values while transaction and integration costs associated with the acquisitions are expensed as incurred. The fair value measurements of oil and natural gas properties, other assets and ARO are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties, other assets and ARO were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. ARO assumptions include inputs such as expected economic recoveries of oil and natural gas and time to abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change. 2015 Acquisitions & Other Transactions On March 31, 2015, we completed the acquisition of certain CO 2 producing properties located in Harding County, New Mexico (“CO 2 Assets”), for a total purchase price of $70.5 million (the “CO 2 Acquisition”), of which $13.7 million was paid in cash at closing and $0.6 million was paid in cash during the fourth quarter of 2015. The purchase price included $70.5 million reflected in other property, plant and equipment on the consolidated balance sheet (including $49.9 million of CO 2 supply advances and deposits paid in 2013 and 2014 and reclassified from other long-term assets to other property, plant and equipment during the six months ended June 30, 2015 and $5.1 million of intangibles reclassified from intangibles to other property, plant and equipment during the six months ended June 30, 2015) and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet. In May 2015, we completed the acquisition of additional interests in our existing fields located in Ark-La-Tex for a total preliminary purchase price of $3.0 million , which is primarily reflected in oil and natural gas properties on the consolidated balance sheet. In August 2015, we granted a three-year term assignment of our interests in certain oil and gas leases in the Mississippian, Woodford, and Hunton formations in Kingfisher County, Oklahoma for cash consideration of $3.2 million . We reserved all existing wellbores and the production therefrom and reserved an overriding royalty interest equal to the difference between existing lease burdens appearing of record and 20% , which was later sold in December 2015 for cash consideration of $3.6 million . In September 2015, we entered into an agreement to exchange certain of our non-contiguous acres in Martin County, Texas for non-operated producing assets in Weld County, Colorado and cash consideration of $4.8 million . We recorded a gain of $7.8 million on this transaction. The trade was for all future horizontal and vertical development rights in the oil and gas leases exchanged. We reserved all existing wellbores and the production therefrom in these Martin County, Texas acres. 2014 Acquisitions QR Energy, LP On November 19, 2014, we completed the merger with QRE. Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QRE (a “QRE Common Unit”) and Class B Unit representing a limited partner interest in QRE (a “Class B Unit”) was converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A total of 6,748,067 Class B Units, issuable upon a change of control of QRE, were issued and treated as outstanding and along with 6,133,558 previously issued Class B Units were converted into the right to receive the Merger Consideration. Each outstanding Class C Unit (a “Class C Unit”) of QRE was converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the QRE Merger. We issued approximately 71.5 million Common Units as part of the Merger Consideration. In connection with the consummation of the QRE Merger, the New York Stock Exchange (the “NYSE”) was notified that each outstanding QRE Common Unit was converted into the right to receive the Merger Consideration described above, subject to the terms and conditions of the Merger Agreement. On November 21, 2014, the NYSE filed a notification of removal from listing on Form 25 with the SEC with respect to delisting the QRE Common Units. We acquired a 59% controlling interest in ETSWDC and have consolidated ETSWDC into our consolidated financial statements. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields. The final purchase price, for the 2014 QRE Merger, which was determined by management with the assistance of outside valuation consulting firms was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Cash $ 5,121 Accounts and other receivables 113,398 Current derivative instrument assets 70,362 Prepaid expenses 3,123 Oil and gas properties 2,397,967 Non-oil and gas assets 17,866 Goodwill 95,947 Long-term derivative instrument assets 72,998 Other long-term assets 50,619 Accounts payable and accrued liabilities (157,916 ) Current derivative instrument liabilities (6,512 ) Current asset retirement obligation (2,618 ) Credit facility debt (790,000 ) Senior notes at fair value (344,129 ) Long-term asset retirement obligation (91,465 ) Long-term derivative instrument liabilities (8,877 ) Other long-term liabilities (10,277 ) Non-controlling interest (7,173 ) $ 1,408,434 Acquisition-related costs for the QRE Merger were $11.8 million for the year ended December 31, 2014 and are reflected in G&A expenses on the consolidated statement of operations. For the year ended December 31, 2014, we recorded $42.1 million in revenue and $24.9 million in lease operating expenses, including production and property taxes, from the 2014 QRE Merger. On November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC (“QRM”). Under the terms of the TSA, each party agreed to provide certain land administrative, accounting, IT and marketing services to the other party. The term of the TSA commenced on November 19, 2014 and terminated on May 19, 2015. In connection with the QRE Merger, we assumed QRE’s 9.25% Senior Notes due 2020 (the “QRE Notes”), with an aggregate principal amount of $300 million , and a carrying amount of $297.0 million , net of $3.0 million of unamortized discount. We recognized the QRE Notes at their fair value at the close of the Merger of $344.1 million . Upon the closing of the QRE Merger, on November 19, 2014, QRE issued notices of redemption to the holders of the QRE Notes, specifying a redemption date of December 19, 2014 for 35% of the QRE Notes at a redemption price of 109.25% and a redemption date of December 22, 2014 for the remaining QRE Notes at a redemption price equal to 117.67% in accordance with the terms of its indenture, plus accrued and unpaid interest to the redemption dates. On November 19, 2014, QRE also placed in trust with the trustee sufficient funds to redeem all of the outstanding QRE Notes and pay accrued and unpaid interest thereon to, but not including, the applicable redemption dates. As a result, on November 19, 2014, QRE was released from its obligations under the QRE Notes and the indenture governing the QRE Notes pursuant to the satisfaction and discharge provisions described therein. Antares Acquisition On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, a Delaware corporation, in exchange for 4.3 million Common Units and $50.0 million in cash (the “Antares Acquisition”), for a total purchase price of $122.3 million . The final purchase price was allocated to oil and natural gas assets as follows: $110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO. 2013 Acquisitions Oklahoma Panhandle Acquisitions On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain carbon dioxide (“CO 2 ”) supply contracts, certain oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $845 million in cash (the “Whiting Acquisition”), including post-closing adjustments. We used borrowings under our credit facility to fund this acquisition. The final purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Oil and gas properties - proved $ 700,963 Oil and gas properties - unproved 43,492 Pipeline and processing facilities 74,537 Derivative assets - current 15 Intangibles 14,739 Derivative assets - long-term 16,183 Other long-term assets 10,936 Derivative liabilities - current (6,347 ) Accrued liabilities (1,115 ) Asset retirement obligation (8,102 ) $ 845,301 Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price crude oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO 2 purchase contracts that we received in the acquisition. An intangible asset was established to value the portion of the CO 2 contracts that were above market at closing in the purchase price allocation. We amortize the CO 2 contracts based on the amount of CO 2 purchases made in each period over the contracts’ respective lives.We were also novated a $10.9 million long-term advance relating to future CO 2 supply contract arrangements. See Note 8 for further details on the intangibles and other long-term assets acquired. We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013, subject to customary post-closing adjustments (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). The additional interests were allocated $17.8 million to oil and natural gas properties and $12.4 million to pipeline facilities. We used borrowings under our credit facility to fund the Oklahoma Panhandle Acquisitions. Acquisition-related costs for the Oklahoma Panhandle Acquisitions of $3.3 million ( $3.2 million recorded in 2013), were included in G&A expenses on the consolidated statements of operations. For the year ended December 31, 2013, we recorded approximately $104.9 million in sales revenue and $29.9 million in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions. Permian Basin Acquisitions On December 30, 2013, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P. for approximately $282 million in cash (the “CrownRock III Acquisition”). We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013 (together with the CrownRock III Acquisition, the “2013 Permian Basin Acquisitions”). The final purchase price for 2013 Permian Basin Acquisitions was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Oil and gas properties - proved $ 258,728 Oil and gas properties - unproved 44,451 Asset retirement obligation $ (1,069 ) $ 302,110 Acquisition-related costs for the 2013 Permian Basin Acquisitions were $0.6 million and $0.1 million for the years ended December 31, 2014 and 2013 , respectively, and are reflected in G&A expenses on the consolidated statements of operations. For the year ended December 31, 2013, we recorded two days of sales revenue less lease operating expenses and production and property taxes of $0.2 million from our 2013 Permian Basin Acquisitions. Pro Forma (unaudited) The following unaudited pro forma financial information presents a summary of our combined statements of operations for the years ended December 31, 2014 and 2013 assuming: (i) the QRE Merger was completed on January 1, 2013 and (ii) the Whiting Acquisition and additional acquired assets in the Oklahoma Panhandle acquisitions and the 2013 Permian Basin Acquisitions were completed on January 1, 2012. The pro forma results reflect the results of combining our statements of operations with the results of operations from all of our 2013 and 2014 acquisitions, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs, and (4) the effect on the denominator for calculating net income (loss) per unit of common unit issuances necessary to finance the acquisitions. The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2014 or 2013 . The Antares Acquisition in 2014 was not included in the pro forma information as Antares represented less than 0.1% of our 2014 revenue, and is considered immaterial. Pro Forma Year Ended December 31, Thousands of dollars, except per unit amounts 2014 2013 Revenues $ 1,947,315 $ 1,280,718 Net income attributable to the partnership 541,935 102,486 Net income per common unit: Basic $ 2.51 $ 0.49 Diluted $ 2.50 $ 0.49 |
Financial Instruments and Fair
Financial Instruments and Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Financial Instruments [Abstract] | |
Financial Instruments and Fair Value Measurement | Financial Instruments and Fair Value Measurements Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have entered into economic hedges for a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increases, our margins would be adversely affected. Commodity Activities Due to the historical volatility of oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not currently designate any of our derivative instruments as cash flow hedges for financial accounting purposes and instead recognize changes in fair value in earnings. We had the following oil contracts in place at December 31, 2015 : Year 2016 2017 2018 2019 Oil Positions: Fixed Price Swaps - NYMEX WTI Volume (Bbl/d) 17,504 14,519 1,493 1,000 Average Price ($/Bbl) $ 83.62 $ 82.81 $ 64.02 $ 56.35 Fixed Price Swaps - ICE Brent Volume (Bbl/d) 4,300 298 — — Average Price ($/Bbl) $ 95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d) 1,500 — — — Average Floor Price ($/Bbl) $ 80.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 102.00 $ — $ — $ — Collars - ICE Brent Volume (Bbl/d) 500 — — — Average Floor Price ($/Bbl) $ 90.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 101.25 $ — $ — $ — Puts - NYMEX WTI Volume (Bbl/d) 1,000 — — — Average Price ($/Bbl) $ 90.00 $ — $ — $ — Total: Volume (Bbl/d) 24,804 14,817 1,493 1,000 Average Price ($/Bbl) $ 85.79 $ 83.11 $ 64.02 $ 56.35 We had the following natural gas contracts in place at December 31, 2015 : Year 2016 2017 2018 2019 Gas Positions: Fixed Price Swaps - MichCon City-Gate Volume (MMBtu/d) 29,000 24,000 17,500 10,000 Average Price ($/MMBtu) $ 3.91 $ 3.71 $ 3.10 $ 3.15 Fixed Price Swaps - Henry Hub Volume (MMBtu/d) 42,050 21,016 2,870 — Average Price ($/MMBtu) $ 4.02 $ 4.29 $ 3.74 $ — Collars - Henry Hub Hedged Volume (MMBtu/d) 630 595 — — Average Floor Price ($/MMBtu) $ 4.00 $ 4.00 $ — $ — Average Ceiling Price ($/MMBtu) $ 5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume (MMBtu/d) 11,350 10,445 — — Average Price ($/MMBtu) $ 4.00 $ 4.00 $ — $ — Deferred Premium ($/MMBtu) $ 0.66 (a) $ 0.69 (b) $ — $ — Total: Volume (MMBtu/d) 83,030 56,056 20,370 10,000 Average Price ($/MMBtu) $ 3.98 $ 3.98 $ 3.19 $ 3.15 (a) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume. (b) Deferred premiums of $0.69 apply to 10,445 MMBtu/d of the 2017 volume. During the years ended December 31, 2015 and 2014 , we did not enter into any derivative instruments that required prepaid premiums. During the years ended December 31, 2015 , 2014 and 2013 , $6.7 million , $8.5 million and $4.9 million , respectively, of premiums paid in 2012 related to oil and gas derivatives settled. As of December 31, 2015 , premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2016 and beyond were as follows: Year Thousands of dollars 2016 2017 2018 2019 Oil $ 7,438 $ 734 $ — $ — Natural gas 952 — — — Interest Rate Activities We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at December 31, 2015 : Year 2016 2017 Fixed Rate Swaps - LIBOR Notional Amount (thousands of dollars) $ 710,000 $ 200,000 Average Fixed Rate 1.28 % 1.23 % We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes. Fair Value of Derivative Instruments FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The required disclosures are detailed below. Fair value of derivative instruments not designated as hedging instruments: Balance sheet location, thousands of dollars Oil Commodity Derivatives Natural Gas Commodity Derivatives Interest Rate Derivatives Commodity Derivatives Netting (a) Total Financial Instruments As of December 31, 2015 Assets Current assets - derivative instruments $ 397,748 $ 44,426 $ 222 $ (2,769 ) $ 439,627 Other long-term assets - derivative instruments 202,140 27,105 216 (2,697 ) 226,764 Total assets 599,888 71,531 438 (5,466 ) 666,391 Liabilities Current liabilities - derivative instruments (15 ) (2,740 ) (4,476 ) 2,769 (4,462 ) Long-term liabilities - derivative instruments — (2,865 ) (87 ) 2,697 (255 ) Total liabilities (15 ) (5,605 ) (4,563 ) 5,466 (4,717 ) Net assets (liabilities) $ 599,873 $ 65,926 $ (4,125 ) $ — $ 661,674 As of December 31, 2014 Assets Current assets - derivative instruments $ 350,351 $ 58,246 $ — $ (445 ) $ 408,152 Other long-term assets - derivative instruments 296,441 29,649 210 (6,740 ) 319,560 Total assets 646,792 87,895 210 (7,185 ) 727,712 Liabilities Current liabilities - derivative instruments (214 ) (563 ) (5,126 ) 445 (5,458 ) Long-term liabilities - derivative instruments (1,520 ) (5,220 ) (2,269 ) 6,740 (2,269 ) Total liabilities (1,734 ) (5,783 ) (7,395 ) 7,185 (7,727 ) Net assets (liabilities) $ 645,058 $ 82,112 $ (7,185 ) $ — $ 719,985 (a) Represents counterparty netting under derivative netting agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These contracts are reflected net on the consolidated balance sheet. The following table presents gains and losses on derivative instruments not designated as hedging instruments: Location of gain (loss), thousands of dollars Oil Commodity Derivatives (a) Natural Gas Commodity Derivatives (a) Interest Rate Derivatives (b) Total Financial Instruments Year Ended December 31, 2015 Net gain (loss) $ 385,887 $ 52,727 $ (2,691 ) $ 435,923 Year Ended December 31, 2014 Net gain $ 526,335 $ 40,198 $ 490 $ 567,023 Year Ended December 31, 2013 Net gain (loss) $ (34,259 ) $ 5,077 $ — $ (29,182 ) (a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. (b) Included in (gain) loss on interest rate swaps on the consolidated statements of operations. Fair Value Measurements FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows: Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2015 and 2014 , our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options. Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2015 , 2014 and 2013 . Our policy is to recognize transfers between levels as of the end of the period. Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Derivative Instruments We calculate the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements. The models we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments are standard option pricing models. Level 2 inputs to the pricing models include the terms of our derivative contracts, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from independent third party data providers and our counterparties and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatilities, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting. Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments. The fair value of the commodity and interest rate derivative instruments that were novated to us in connection with the 2014 QRE Merger were estimated using a combined income and market valuation methodology based upon forward commodity prices and volatility curves. The curves were obtained from independent pricing services reflecting broker market quotes. We validated the data provided by independent pricing services by comparing such pricing against other third party pricing data. Available-for-Sale Securities The fair value of our available-for-sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data. We consider the inputs to the valuation of our available for sale securities to be Level 1. Fair Value Hierarchy The following table sets forth, by level within the hierarchy, the fair value of our financial instrument assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . All fair values reflected below and on the consolidated balance sheets have been adjusted for nonperformance risk. Thousands of dollars Level 1 Level 2 Level 3 Total As of December 31, 2015 Assets (liabilities) Oil derivative instruments Oil swaps $ — $ 552,552 $ — $ 552,552 Oil collars — — 29,737 29,737 Oil puts — — 17,584 17,584 Natural gas derivative instruments Natural gas swaps — 54,182 — 54,182 Natural gas collars — — 618 618 Natural gas puts — — 11,126 11,126 Interest rate swaps Interest rate swaps — (4,125 ) — (4,125 ) Available-for-sale securities Equities 2,524 — — 2,524 Mutual Funds 11,190 — — 11,190 Exchange traded funds 4,977 — — 4,977 Net assets $ 18,691 $ 602,609 $ 59,065 $ 680,365 As of December 31, 2014 Assets (liabilities) Oil derivative instruments Oil swaps $ — $ 583,648 $ — $ 583,648 Oil collars — — 44,405 44,405 Oil puts — — 17,005 17,005 Natural gas derivative instruments Natural gas swaps — 62,220 — 62,220 Natural gas collars — — 13,256 13,256 Natural gas puts — — 6,636 6,636 Interest rate swaps Interest rate swaps — (7,185 ) — (7,185 ) Available-for-sale securities Equities 4,138 — — 4,138 Mutual Funds 10,577 — — 10,577 Exchange traded funds 4,630 — — 4,630 Net assets $ 19,345 $ 638,683 $ 81,302 $ 739,330 The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: Year End December 31, 2015 2014 2013 Thousands of dollars Oil Natural Gas Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 61,410 $ 19,892 $ 8,957 $ 1,848 $ 15,169 $ 1,672 Derivative instrument settlements (b) 44,647 16,815 4,094 815 (125 ) (892 ) Gain (loss) (b)(c) (58,736 ) (24,963 ) 37,189 5,357 (6,087 ) 1,068 Purchases (b)(d) — — 11,170 11,872 — — Ending balance $ 47,321 $ 11,744 $ 61,410 $ 19,892 $ 8,957 $ 1,848 (a) We had no fair value changes for our derivative instruments classified as Level 3 related to sales or issuances. (b) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. (c) Represents gain (loss) on mark-to-market of derivative instruments. (d) 2014 purchases related to derivative instruments novated to us in connection with the QRE Merger. For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2015 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars December 31, 2015 Technique Unobservable Input Range Oil options $ 47,321 Option Pricing Model Oil forward commodity prices $37.04/Bbl - $47.79/Bbl Oil volatility 32.24% - 44.95% Own credit risk 5% Natural gas options 11,744 Option Pricing Model Gas forward commodity prices $2.34/MMBtu - $2.99/MMBtu Gas volatility 23.44% - 73.05% Own credit risk 5% Total $ 59,065 For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2014 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars December 31, 2014 Technique Unobservable Input Range Oil options $ 61,410 Option pricing model Oil forward commodity prices $53.27/Bbl - $71.66/Bbl Oil volatility 29.21% - 46.16% Own credit risk 5% Natural gas options 19,892 Option pricing model Gas forward commodity prices $2.88/MMBtu - $3.99/MMBtu Gas volatility 18.59% - 63.51% Own credit risk 5% Total $ 81,302 Credit and Counterparty Risk Financial instruments, which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of December 31, 2015 , our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A., Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders under our Credit Agreement. Our credit agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2015 , each of these financial institutions had an investment grade credit rating. As of December 31, 2015 , our largest derivative asset balances were with Wells Fargo Bank, N.A. , Barclays Bank PLC , Credit Suisse Energy LLC and Morgan Stanley Capital Group Inc. , which accounted for approximately 15% , 13% , 11% and 11% of our derivative asset balances, respectively. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Breitburn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of Breitburn Management. Breitburn Management also provides administrative services to PCEC, our Predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For each of the years ended December 31, 2015 and 2014 , the monthly fee paid by PCEC for indirect expenses was $700,000 . On May 1, 2015, Breitburn Management and PCEC entered into Amendment No. 5 to the Administrative Services Agreement (“ASA”), extending the term of the ASA to December 31, 2016; provided, however, in the event PCEC has not received certain permits by December 31, 2015, PCEC may terminate the ASA effective as of June 30, 2016 by giving prior written notice to Breitburn Management of its intention to terminate the ASA by December 31, 2015. The deadline to provide notice of termination was extended on December 22, 2015 to January 31, 2016 and again on January 29, 2016 to February 8, 2016. On February 5, 2016, PCEC provided written notice to Breitburn Management of its intention to terminate the ASA effective as of June 30, 2016. At December 31, 2015 and 2014 , we had net current receivables of $1.7 million and $2.4 million , respectively, due from PCEC related to the applicable administrative services agreement, employee related costs and oil and gas sales made by PCEC on our behalf from certain properties. For the years ended December 31, 2015 , 2014 , and 2013 , the monthly charges to PCEC for indirect expenses totaled $8.4 million , $8.4 million and $8.4 million , respectively, and charges for direct expenses including direct payroll and other direct costs totaled $9.6 million , $10.9 million and $10.6 million , respectively. Effective on April 8, 2015, the closing date of private offerings of senior secured second lien notes and perpetual convertible preferred units (see Note 9 and Note 15, respectively), Kurt A. Talbot, then Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the board of directors of Breitburn GP LLC, our General Partner. We paid EIG Management Company, LLC, an affiliate of EIG, a transaction fee of $13 million with respect to the purchase of the senior secured second lien notes and a transaction fee of $7 million with respect to the purchase of the perpetual convertible preferred units. |
Impairments
Impairments | 12 Months Ended |
Dec. 31, 2015 | |
Impairments and Price Related Depletion and Depreciation Adjustments [Abstract] | |
Impairments | Impairments Long-Lived Assets Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2% per year. Production and development cost estimates (e.g. operating expenses and development capital) are conformed where applicable to reflect the commodity price strip used. For impairment charges, the associated property’s expected future net cash flows were discounted using a market-based long-term weighted average cost of capital rate that currently approximates 10% . Additional inputs include oil and natural gas reserves, future operating and development costs and future commodity prices. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. During the year ended December 31, 2015 , we recorded non-cash impairments related to our oil, NGL and natural gas properties of $2.4 billion , including $740.6 million in the Midwest, $512.8 million in Ark-La-Tex, $443.8 million in the Southeast, $256.5 million in the Permian Basin, $213.0 million in California, $147.9 million in the Rockies, and $63.0 million in Mid-Continent. The impairments were primarily due to the impact that the sustained drop in commodity strip prices had on our projected future net revenues. During the year ended December 31, 2014, we recorded non-cash impairments related to our oil, NGL and natural gas properties of $149.0 million , including $124.8 million in the Southeast, $11.2 million in the Rockies, $8.5 million in the Midwest, $2.3 million in the Permian Basin and $2.2 million in Mid-Continent. The impairments in the Southeast were due to reserve adjustments primarily related to lower crude oil prices and well performance. The Rockies impairments were due to reserve adjustments related to a combination of lower oil prices, well performance and higher expense projections. The Midwest impairments related to lower commodity prices and the write-off of investments associated with expiring leases that we elected not to renew. The Permian Basin and Mid-Continent property impairments related to lower commodity prices. During the year ended December 31, 2013, we recorded non-cash impairment charges of approximately $54.4 million , including $28.3 million of impairments to our Michigan non-Antrim oil and gas properties due to negative reserve adjustments due to lower performance and a decrease in expected future commodity prices, and $25.3 million of impairments to an oil property in our Bighorn Basin in Northern Wyoming due to a negative reserve adjustment due to lower performance and a decrease in expected future oil prices. Decreased drilling activity in Michigan was also a factor as we continued to allocate our capital expenditures more towards liquids-rich areas. Given the number of assumptions involved in the estimates, an estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused additional impairment charges to those assets that were impaired and/or additional assets that were not impaired. Goodwill Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and then charged to impairment expense. The analysis of the potential impairment of goodwill is a two-step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of goodwill impairment. If the fair value of the reporting unit is less than its carrying value, step two of the goodwill impairment test is performed. Step two consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment. As of March 31, 2015, we had $95.9 million of goodwill related to the 2014 QRE Merger (see Note 3). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill. Based on this assessment, we recorded a non-cash goodwill impairment charge of $95.9 million during the second quarter of 2015. |
Investments (Notes)
Investments (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Investments [Abstract] | |
Investments | Investments Our available-for-sale securities comprise primarily of equity, mutual funds and exchange traded funds. They consist of investments not classified as trading securities or as held-to-maturity. Our investments are included in other long-term assets on our consolidated balance sheets. As of December 31, 2015 , we had the following available-for-sale investments outstanding: Gross Gross Thousands of dollars Cost Basis Unrealized Gains Unrealized Losses Fair Value Available-for-sale securities: Equities $ 2,591 $ 141 $ (208 ) $ 2,524 Mutual funds 13,276 1,737 (3,823 ) 11,190 Exchange traded funds 3,721 1,494 (238 ) 4,977 Total available-for-sale securities $ 19,588 $ 3,372 $ (4,269 ) $ 18,691 As of December 31, 2014 , we had the following available-for-sale investments outstanding: Gross Gross Thousands of dollars Cost Basis Unrealized Gains Unrealized Losses Fair Value Available-for-sale securities: Equities $ 4,203 $ 92 $ (157 ) $ 4,138 Mutual funds 10,623 20 (66 ) 10,577 Exchange traded funds 4,808 27 (205 ) 4,630 Total available-for-sale securities $ 19,634 $ 139 $ (428 ) $ 19,345 During the years ended December 31, 2015 and 2014, we received $3.9 million and $0.5 million , respectively, in proceeds from the sale of available-for-sale securities, and recognized a realized loss of $0.1 million and a realized loss of less than $0.1 million , respectively, reflected in other expense (income), net on the consolidated statements of operations. We evaluate securities for other than temporary impairment on a quarterly basis and more frequently when economic or market concerns warrant such an evaluation. The unrealized losses in the table above have been outstanding for less than two months. We have evaluated the unrealized losses and have determined that these losses do not represent an other than temporary impairment. Fair value of our available for sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data. |
Other Assets (Notes)
Other Assets (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Other Assets [Abstract] | |
Other Assets | Other Long-Term Assets As of December 31, 2015 and 2014 , our other long-term assets were $117.9 million and $165.4 million , respectively, consisting of the following: As of December 31, Thousands of dollars 2015 2014 Debt issuance costs (Note 9) 59,167 52,787 Available-for-sale securities (Note 7) 18,691 19,345 Deposit for Jay Field net profit interest obligation 18,263 18,263 Property reclamation deposit 10,736 10,735 CO 2 supply advances and deposits (Note 3) — 50,792 Intangible assets 365 8,336 Other 10,650 5,120 Total 117,872 165,378 NPI Obligation We have a net profit interest (“NPI”) related to the Jay Field. Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical productions costs. Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to the extent the NPI for that month exceeds the amount withheld for that month for future development costs and abandonment obligations. The NPI holder’s share of excess historical production costs amounted to $9.8 million and $2.3 million at December 31, 2015 and 2014 , respectively. In addition, we will retain the NPI holder’s shares of future development costs and abandonment obligations, subject to future production, production costs, and capital spending level, which will be paid using the funds withheld. The NPI holder’s share along with our share of the abandonment costs as of December 31, 2015 are reflected in asset retirement obligation on the consolidated balance sheet. Under the arrangement, we have the option to deposit into a separate account the funds withheld from the NPI holder for their portion of the future development costs and abandonment obligations. The funds totaled $18.3 million as of December 31, 2015 and 2014 , which is reflected in other long-term assets on the consolidated balance sheet. Property Reclamation Deposit We have a property reclamation deposit of $10.7 million in an escrow account as security for future abandonment and remediation obligations for the Jay Field. As of December 31, 2015 and 2014 , $10.7 million was recorded in other long-term assets related to the deposit. We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller’s sole discretion. In addition to the cash deposit, we are required to provide letters of credit. At December 31, 2015 and 2014 , we had $23.4 million in letters of credit related to the property reclamation deposit. Intangible Assets In connection with the 2013 Whiting Acquisition (see Note 3), we acquired two CO 2 purchase contracts that were priced below market, which were valued at $14.7 million at the acquisition date. These contracts were recorded as finite-lived intangibles. We amortize these contracts based on the amount of CO 2 purchases made in each period over the contracts’ respective lives. For the years ended December 31, 2015 , 2014 and 2013 , we recorded $2.2 million , $3.9 million and $3.6 million , respectively, in amortization expense related to these contracts. In connection with the CO 2 Acquisition in 2015, we reclassified $5.1 million of the remaining CO 2 purchase contract from intangibles to other property, plant and equipment. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Long-term Debt, Unclassified [Abstract] | |
Long-Term Debt | Long-Term Debt Our long-term debt is detailed in the following table: As of December 31, Thousands of dollars 2015 2014 Credit facility $ 1,229,000 $ 2,194,500 Promissory note 2,938 1,100 9.25% Senior Secured Notes due 2020 650,000 — 8.625% Senior Unsecured Notes due 2020 305,000 305,000 7.875% Senior Unsecured Notes due 2022 850,000 850,000 Net (discount) premium on Senior Notes (15,781 ) 1,560 Total debt 3,021,157 3,352,160 Less: Current portion of long-term debt (154,000 ) (105,000 ) Total long-term debt $ 2,867,157 $ 3,247,160 Credit Facility BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $5.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks with a maturity date of November 19, 2019. We entered into the Third Amended and Restated Credit Agreement on November 19, 2014, in connection with the 2014 QRE Merger. On April 8, 2015, in connection with financing and related party transactions with EIG Global Energy Partners, we entered into the First Amendment (the “First Amendment”) to the Credit Agreement (as amended, the “Credit Agreement”). Among other changes, the First Amendment: (i) established a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our Common Units or voluntary prepayment of second lien indebtedness; and (v) added a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units (as defined below). Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually. Currently, our borrowing base for our credit facility is $1.8 billion , and the aggregate commitment of all lenders is $1.8 billion . Our next borrowing base redetermination is scheduled for April 2016. The Credit Agreement requires us to maintain an Interest Coverage Ratio (defined as EBITDAX divided by Consolidated Interest Expense) and a Current Ratio (defined as current assets divided by current liabilities) for the four quarters ending on the last day of each quarter beginning with the fourth quarter of 2014 of no less than 2.50 to 1.00 and 1.00 to 1.00 , respectively. EBITDAX is not a defined US GAAP measure. The Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments for the following twelve months), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Credit Agreement) and excluding income from our unrestricted entities. If any acquisition or disposition was consummated during an applicable quarter, all calculations of EBITDAX shall be determined on a pro forma basis. As of December 31, 2015 and 2014 , we had $1.2 billion and $2.2 billion , respectively, in indebtedness outstanding under the credit facility. At December 31, 2015 , the 1-month LIBOR interest rate plus an applicable spread was 2.6084% on the 1-month LIBOR portion of $1.2 billion . During the year ended December 31, 2015 , we recognized a write-off of $10.6 million of debt issuance costs, included in interest expense, net of capitalized interest on the consolidated statements of operations, relating to the reduction of our credit facility borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing. At December 31, 2015 and 2014 , we had $22.1 million and $33.5 million , respectively, of unamortized debt issuance costs related to our credit facility. Borrowings under the Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties. The Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. As of December 31, 2015 and 2014 , we were in compliance with our credit facility’s covenants. The Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination. The events that constitute an Event of Default (as defined in the Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims. The carrying value of our credit facility as of December 31, 2015 approximated fair value. We consider the fair value of our credit facility to be Level 2, as it is based on the current active market 1-month LIBOR. Promissory Note ETSWDC, as borrower, has a secured $6.0 million Promissory Note with Texas Capital Bank, NA, with a maturity date of November 13, 2019. As of December 31, 2015 and 2014 , ETSWDC had $2.9 million and $1.1 million , respectively, outstanding under the Promissory Note. At December 31, 2015 , the 1-month LIBOR interest rate plus an applicable spread was 2.3584% . Senior Secured Notes On April 8, 2015, we issued $650 million of 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”) in a private offering to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $606.9 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. Interest on our Senior Secured Notes is payable quarterly in March, June, September and December. As of December 31, 2015 , our Senior Secured Notes had a carrying value of $632.7 million , net of unamortized discount of $17.3 million . As of December 31, 2015 , the fair value of our Senior Secured Notes was estimated to be approximately $518 million , based on quoted yields for similarly rated debt instruments currently available in the market, and we consider the valuation of our Senior Secured Notes to be Level 3. At December 31, 2015 , we had $20.6 million , of unamortized debt issuance costs related to our Senior Secured Notes. Senior Unsecured Notes As of December 31, 2015 , we had $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were offered at a discount price of 98.358% , or $300 million . The $5 million discount is being amortized over the life of the 2020 Senior Notes. In addition, as of December 31, 2015 , we had $850 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “2022 Senior Notes”). Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October. As of December 31, 2015 and 2014 , the 2020 Senior Notes had a carrying value of $302.1 million and $302.1 million , respectively, net of unamortized discount of $2.9 million and $2.9 million , respectively. As of December 31, 2015 and 2014 , the fair value of the 2020 Senior Notes was estimated to be $59 million and $262 million , respectively. We consider the inputs to the valuation of our 2020 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions. In connection with the 2020 Senior Notes, we incurred financing fees and expenses of approximately $8.8 million , which are being amortized over the life of the 2020 Senior Notes. At December 31, 2015 and 2014 , unamortized debt issuance costs related to our 2020 Senior Notes were $4.2 million and $5.1 million , respectively. As of December 31, 2015 and 2014 , the 2022 Senior Notes had a carrying value of $854.5 million and $854.5 million , respectively, net of unamortized premium of $4.5 million and $4.5 million , respectively. Interest on the 2022 Senior Notes is payable twice a year in April and October. As of December 31, 2015 and 2014 , the fair value of the 2022 Senior Notes was estimated to be $157 million and $661 million , respectively. We consider the inputs to the valuation of our 2022 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions. At December 31, 2015 and 2014 , unamortized debt issuance costs related to our 2022 Senior Notes were $12.2 million and $14.1 million , respectively. The indentures governing both our 2020 Senior Notes and 2022 Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; or (x) engage in certain business activities. If the 2020 Senior Notes and 2022 Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indentures) has occurred and is continuing, many of these covenants will terminate. As of December 31, 2015 and December 31, 2014 , we were in compliance with the covenants on our 2020 Senior Notes and 2022 Senior Notes. Interest Expense Our interest expense is detailed in the following table: Year Ended December 31, Thousands of dollars 2015 2014 2013 Credit facility (including commitment fees) $ 41,254 $ 23,788 $ 15,698 Senior Secured Notes 43,758 — — Senior Unsecured Notes 93,244 95,662 65,068 Amortization of discount/premium and deferred issuance costs (a) 24,926 7,836 6,429 Capitalized interest (155 ) (326 ) (128 ) Total $ 203,027 $ 126,960 $ 87,067 Cash paid for interest $ 181,873 $ 119,488 $ 74,078 (a) The year ended December 31, 2015 included a write-off of $10.6 million of debt issuance costs related to the reduction of our credit facility borrowing base. |
Condensed Consolidating Financi
Condensed Consolidating Financial Statements | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Statements | Condensed Consolidating Financial Statements We and Breitburn Finance (and BOLP, with respect to the Senior Secured Notes) as co-issuers, and certain of our subsidiaries as guarantors, issued the Senior Secured Notes and the Senior Unsecured Notes (collectively, the “Senior Notes”). All but two of our subsidiaries have guaranteed our Senior Notes. Our only non-guarantor subsidiaries, Breitburn Utica and ETSWDC, are minor subsidiaries. In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; Breitburn Finance, the subsidiary co-issuer, which does not guarantee the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned, have guaranteed the Senior Notes, and all of the guarantees are full, unconditional, joint and several. Each guarantee of the Senior Notes is subject to release in the following customary circumstances: (1) a disposition of all or substantially all the assets of the guarantor subsidiary (including by way or merger or consolidation), to a third person, provided the disposition complies with the applicable indenture, (2) a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary, (3) the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary in accordance with the applicable indenture, (4) legal or covenant defeasance of such series of Senior Notes or satisfaction and discharge of the related indenture, (5) the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or (6) the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Breitburn Management, ETSWDC, Alamitos Company, Breitburn Finance and QRE Finance Corporation (“QRE Finance”), are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following: Year Ended December 31, Thousands of dollars 2015 2014 2013 Federal income tax expense (benefit) Current $ 626 $ 212 $ 472 Deferred (a) 784 (173 ) 262 Current state income tax expense (benefit) (b) 117 (112 ) 171 Total $ 1,527 $ (73 ) $ 905 (a) Related to Phoenix and Breitburn Management, our wholly-owned subsidiaries, and ETSWDC, a subsidiary we have a controlling interest in. (b) Primarily in California and Texas. At December 31, 2015 and 2014 , a net deferred federal income tax liability of $3.4 million and $2.0 million , respectively, was reported on our consolidated balance sheet for Phoenix, Breitburn Management and ETSWDC, including a liability reflected in deferred income taxes of $3.8 million and $2.6 million , respectively, and deferred tax asset of $0.4 million and $0.6 million , respectively, included in other long-term assets on the consolidated balance sheet. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes. Significant components of our net deferred tax liabilities are presented in the following table: December 31, Thousands of dollars 2015 2014 Deferred tax assets: Asset retirement obligation $ 2,296 $ 2,120 Operating loss carryforwards 3,714 2,341 Unused minimum tax credit — 440 Compensation accruals 1,558 1,315 Pension costs 1,724 2,461 Post-retirement costs 823 952 Other 309 103 Valuation allowance (6,542 ) (4,243 ) Deferred tax liabilities: Depreciation, depletion and intangible drilling costs (6,505 ) (6,455 ) Unrealized hedge gain (825 ) (1,069 ) Net deferred tax liability $ (3,448 ) $ (2,035 ) At December 31, 2015 , we had unused federal net operating loss carryforwards totaling $10.9 million . The net operating loss carryforwards expire between 2026 and 2035. We have not fully recognized the deferred tax assets for certain items in advance of their deductibility for income tax purposes due to uncertainty of realization. The benefit of these items will be recognized in future years to the extent that such deductions are used to reduce taxable income. Approximately $5.9 million of the net operating loss carryforwards acquired in connection with the 2014 QRE Merger, relating to ETSWDC, are subject to an annual utilization limitation of approximately $0.6 million pursuant to the “change in ownership” provisions under Section 382 of the Internal Revenue Code of 1986, as amended. On a consolidated basis, cash paid for federal and state income taxes totaled $0.5 million , $0.2 million and $0.5 million during the years ended December 31, 2015 , 2014 and 2013 , respectively. FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. FASB Accounting Standards also provide guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different companies. We performed analysis as of December 31, 2015 , 2014 and 2013 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligation | Asset Retirement Obligation ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk-free rate that approximated 14% and 7% for the years ended December 31, 2015 and 2014 , respectively, and adjusted for inflation using a rate of 2% . Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk. We consider the inputs to our ARO valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets. Changes in ARO for the years ended December 31, 2015 and 2014 , are presented in the following table: Year Ended December 31, Thousands of dollars 2015 2014 Carrying amount, beginning of period $ 238,411 $ 123,769 Liabilities added from acquisitions 796 95,800 Liabilities incurred from drilling 2,268 4,020 Liabilities settled (7,744 ) (1,708 ) Liabilities related to divested properties (261 ) — Revision of estimates 3,954 6,770 Accretion expense 16,954 9,760 Carrying amount, end of period 254,378 238,411 Less: Current portion of ARO (2,341 ) (4,948 ) Non-current portion of ARO $ 252,037 $ 233,463 |
Pension and Postretirement Bene
Pension and Postretirement Benefits (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Pension and Postretirement Benefits [Abstract] | |
Pension and Postretirement Benefits | Pensions and Postretirement Benefits ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory other post-retirement benefit plan (collectively, the “Plans”) covering substantially all ETSWDC employees who were employed prior to March 31, 2008. Subsequent to March 31, 2008, the Plans were closed to new employees. The tables below set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in our financial statements; and the principal weighted average assumptions used. Obligation and Funded Status The Plans had accumulated benefit obligations in excess of plan assets at December 31, 2015 and 2014 as follows: December 31, 2015 December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Projected benefit obligation $ 25,320 $ 3,971 27,829 4,240 Accumulated benefit obligation 24,424 3,971 26,872 4,240 Fair value of plan assets 20,022 1,468 21,219 1,527 The change in the combined projected benefit obligation of the Plans and the change in the assets at fair value are as follows: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Change in Benefit Obligation Benefit obligation at beginning of year $ 27,829 $ 4,240 $ — $ — 2014 Acquisition of ETSWDC — — 27,300 4,144 Service cost 271 34 33 4 Interest cost 1,014 155 120 18 Plan participant contributions — 28 — 2 Actuarial (gain) loss (2,360 ) (333 ) 496 85 Benefits paid (1,434 ) (153 ) (120 ) (13 ) Benefit obligation at end of year 25,320 3,971 27,829 4,240 Change in Plan Assets Fair value of plan assets at beginning of year 21,219 1,527 — — 2014 Acquisition of ETSWDC — — 21,319 1,518 Actual return on plan assets (163 ) (63 ) 20 9 Employer contributions 400 129 — 11 Plan participant contributions — 28 — 2 Benefits paid (1,434 ) (153 ) (120 ) (13 ) Fair value of plan assets at end of year 20,022 1,468 21,219 1,527 Underfunded status at end of year $ (5,298 ) $ (2,503 ) (6,610 ) (2,713 ) Amounts Recognized on the Consolidated Balance Sheet Amounts recognized on the consolidated balance sheet at December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Long-term liabilities 5,298 2,503 6,610 2,713 Components of Net Periodic Benefit Cost and Other Comprehensive Income Net periodic benefit costs recognized on the consolidated statements of operations for the years ended December 31, 2015 and 2014 consist of the following: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Service cost $ 271 $ 34 $ 33 $ 4 Interest cost 1,014 155 120 18 Expected return on plan assets (1,342 ) (99 ) (152 ) (11 ) Net periodic benefit costs $ (57 ) $ 90 $ 1 $ 11 Amounts recognized in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 consist of the following: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Prior service cost $ — $ — $ — $ — Net actuarial (gain) loss: Liability (gain) loss due to assumption change (2,045 ) (220 ) 474 88 Liability (gain) loss due to participant experience (315 ) (113 ) 22 (3 ) Asset return loss 1,505 162 132 3 Net actuarial (gain) loss (855 ) (171 ) 628 88 Total $ (855 ) $ (171 ) $ 628 $ 88 Estimated Future Benefit Payments As of December 31, 2015 the following estimated benefit payments under the Plans, which reflect expected future service, as appropriate, are expected to be paid as follows: Thousands of dollars Pension Benefits Postretirement Benefits 2016 $ 1,500 $ 150 2017 1,510 170 2018 1,540 190 2019 1,580 210 2020 1,650 230 2021-2025 8,620 1,060 ETSWDC expects to contribute approximately zero and $0.2 million to the pension plan and other postretirement plan, respectively, in 2016 . Assumptions Assumptions used to determine the Plans’ projected benefit obligations and costs as of December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Discount rate 4.10 % 4.10 % 3.75 % 3.75 % Rate of compensation increase 3.00 % N/A 3.00 % N/A Health care cost trend rate: Pre - 65 rate N/A 7.00 % N/A 7.00 % Post - 65 rate N/A 7.00 % N/A 6.00 % Expected long-term rates of return on plan assets 6.75 % 6.75 % 6.50 % 6.50 % Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A 4.5 % N/A 4.5 % Year that the rate reaches the ultimate trend rate N/A 2023 N/A 2022 Assumptions used to determine net periodic benefit costs for the years ended December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Discount rate 3.75 % 3.75 % 3.90 % 3.75 % Expected long-term return on plan assets 6.50 % 6.50 % 6.50 % 6.50 % Rate of compensation increase 3.00 % N/A 3.00 % N/A Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage point increase or decrease in assumed health care cost trend rates would increase or decrease total postretirement benefit service and interest costs by less than $0.1 million and would increase or decrease the postretirement benefit obligation by approximately $0.5 million and $0.4 million , respectively. As of December 31, 2015 and 2014 , we had $8.0 million and $9.6 million , respectively, of equity securities, consisting primarily of pooled separate accounts which focus on long-term growth of capital through U.S. and international services, and $12.0 million and $11.6 million , respectively, of fixed income securities, consisting primarily of pooled separate accounts which focus on long-term growth of capital and preservation of equity through U.S. and international securities. As of December 31, 2015 and 2014 , we had $0.1 million and $0.1 million , respectively, in cash and cash equivalents and $1.4 million and $1.4 million , respectively, in mutual funds, which focus on growth of capital and income maximization. Plan Investment Policies and Strategies The investment policies for the Plans reflect the funded status of the Plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the Plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation. Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. As such, the Plan’s targeted asset allocation is comprised of approximately 50 percent equity securities and approximately 50 percent high-yield bonds and other fixed income securities but may be adjusted to better match the plan's liabilities over time as the funded ratio (as defined by the investment policy) changes. The Plans’ assets are managed by a third party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through annual investment meetings and periodic cash flow studies. Expected long-term return on plan assets The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account the Plan’s asset allocations to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams. Fair Value Measurements Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2015 and 2014 . Cash and cash equivalents – Cash and cash equivalents include cash on deposit which are valued using a market approach and are considered Level 1. Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs. Pooled funds – Investments in pooled funds are valued using a market approach at the net asset value of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Lease Rental and Purchase Obligations We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2015 are presented below: Payments Due by Year Thousands of dollars 2016 2017 2018 2019 2020 Thereafter Total Operating leases $ 11,368 $ 11,323 $ 7,037 $ 5,615 $ 5,648 $ 14,480 $ 55,471 Net rental expense under non-cancelable operating leases was $8.9 million , $5.2 million and $3.9 million in 2015 , 2014 and 2013 , respectively. Surety Bonds and Letters of Credit In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2015 , we had $27.1 million in surety bonds and $25.8 million in letters of credit outstanding, including $23.4 million in letters of credit related to the property reclamation deposit. At December 31, 2014 , we had $21.1 million in surety bonds and $26.5 million in letters of credit outstanding. Legal Proceedings Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject. |
Partners' Equity
Partners' Equity | 12 Months Ended |
Dec. 31, 2015 | |
Partners' Capital [Abstract] | |
Partners' Equity | Partners’ Equity Preferred Units On April 8, 2015, we issued in private offerings $350 million of 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit. We received approximately $337.2 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units (as defined below) with respect to the payment of current distributions. Distributions on the Series B Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15 th day of each month of each year, when, as and if declared by our Board of Directors out of legally available funds for such purpose. For the first monthly distribution on April 24, 2015, we declared a distribution on the Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash of 0.008222 Series B Preferred Unit per unit, which was paid on May 15, 2015. Regular monthly distributions of 0.006666 Series B Preferred Unit began with the June 15, 2015 payment. During the year ended December 31, 2015, we recognized $20.8 million of accrued distributions on the Series B Preferred Units, which are included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations. On April 8, 2015, we entered into a registration rights agreement (“Registration Rights Agreement”) with purchasers of the Series B Preferred Units, including EIG Equity, relating to the registered resale of (1) the Series B Preferred Units, including paid in kind units, and (2) Common Units issuable upon conversion of the Series B Preferred Units, including paid in kind units (the “Registrable Securities”). In certain circumstances, the purchasers of Series B Preferred Units will have piggyback registration rights and rights to request an underwritten offering as described in the Registration Rights Agreement. The Registrable Securities are registered under a shelf registration statement on Form S-3, which was declared effective by the SEC on September 11, 2015. On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million , net of underwriting discounts and offering expenses of $6.8 million . We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility. The Series A Preferred Units rank senior to our Common Units and on parity with the Series B Preferred Units with respect to the payment of current distributions. Distributions on Series A Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per Series A Preferred Unit. During the years ended December 31, 2015 and 2014 , we recognized $16.5 million and $10.1 million , respectively, of accrued distributions on the Series A Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations and paid $16.5 million and $9.4 million , respectively. The Series A Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into Common Units in connection with a change in control. At any time on or after May 15, 2019, we may, at our option, redeem the Series A Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. In addition, we may redeem the Series A Preferred Units at the same redemption price following certain changes of control, as described in the Partnership Agreement (as defined below); if we do not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of Common Units per Preferred Unit as set forth in the Partnership Agreement. If we exercise the right to redeem all outstanding Series A Preferred Units, the holders of Series A Preferred Units will not have the conversion right described above. Common Units At December 31, 2015 and 2014 , we had 213.5 million and 210.9 million in Common Units outstanding, respectively. During the years ended December 31, 2015 and 2014 , approximately 1.6 million and 0.6 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First Amended and Restated 2006 Long Term Incentive Plan (“LTIP”). At each of the years ended December 31, 2015 and 2014 , we had 24.7 million and 9.7 million of Common Units, respectively, authorized for issuance under our long-term incentive compensation plans, and there were 14.1 million and 3.3 million of units available at December 31, 2015 and 2014 , respectively, for future issuance of Common Units. Pursuant to an Equity Distribution Agreement dated as of March 19, 2014 (the “Equity Distribution Agreement”), we may sell, from time to time up to $200 million in Common Units. We intend to use the net proceeds of any sales pursuant to the Equity Distribution Agreement, after deducting commissions and offering expenses, for general purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. The Common Units to be issued are registered under a shelf registration statement on Form S-3, which was declared effective by the SEC on January 22, 2014. During the years ended December 31, 2015 and 2014 , we issued approximately 0.5 million and 1.3 million Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $3.1 million and $26.2 million , respectively. In October 2014, we sold 14 million Common Units at a price to the public of $18.64 per Common Unit. We used the net proceeds, net of underwriting discounts and offering expenses, of $251.6 million to reduce outstanding borrowings under our credit facility. In October 2014, we issued 4.3 million Common Units to Antares as partial consideration for the Antares Acquisition. The fair value of the units on the date of the acquisition was $16.91 per unit, or $72.7 million . In November 2014, we issued 71.5 million Common Units to QRE as partial consideration for the QRE Merger. The fair value of the units on the date of the acquisition was $14.73 per unit, or $1.06 billion . In February 2013, we sold approximately 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in net proceeds of $285.0 million , after deducting underwriting discounts and expenses. In November 2013, we sold 18.98 million Common Units at a price to the public of $18.22 per Common Unit resulting in net proceeds net of $333.2 million , after deducting underwriting discounts and estimated offering expenses. Earnings per Common Unit FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested Restricted Phantom Units (“RPUs”) and Convertible Phantom Units (“CPUs”) participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit. The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit. Year Ended December 31, Thousands, except per unit amounts 2015 2014 2013 Net (loss) income attributable to the partnership $ (2,583,339 ) $ 421,333 $ (43,671 ) Less: Net income (loss) attributable to participating units — 5,348 — Distributions on participating units in excess of earnings 1,731 — — Distributions to Series A preferred unitholders 16,500 10,083 — Non-cash distributions to Series B preferred unitholders 20,817 — — Net (loss) income used to calculate basic and diluted net (loss) income per unit $ (2,622,387 ) $ 405,902 $ (43,671 ) Weighted average number of units used to calculate basic and diluted net income (loss) per unit: Common Units 211,575 133,451 101,604 Dilutive units (a) — 755 — Denominator for diluted net (loss) income per unit 211,575 134,206 101,604 Net (loss) income per common unit Basic $ (12.39 ) $ 3.04 $ (0.43 ) Diluted $ (12.39 ) $ 3.02 $ (0.43 ) (a) The years ended December 31, 2015 and December 31, 2013 exclude 725 and 364 weighted average anti-dilutive units, respectively, from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. Cash Distributions on Common Units The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future. Prior to the fourth quarter of 2013, for the quarters for which we declared a distribution, distributions were paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date. On October 30, 2013, we amended our First Amended and Restated Agreement of Limited Partnership by adopting Amendment No. 5, which provided that, at the discretion of our General Partner, for the quarters for which we declare a distribution, we may pay distributions within 45 days following the end of each quarter or in three equal monthly payments within 17 , 45 and 75 days following the end of each quarter. We changed our distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by our General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. During the years ended December 31, 2015 , 2014 and 2013 , we paid cash distributions of approximately $123.2 million , $261.0 million and $183.6 million , respectively, to our common unitholders. The distributions that were paid to unitholders totaled $0.58 , $2.00 and $1.91 per Common Unit, respectively. We also paid cash equivalent on the distributions paid to our unitholders of $3.0 million , $3.8 million and $3.3 million , respectively, to holders of outstanding RPUs and CPUs issued under our LTIP. Effective November 30, 2015, distributions on common units were suspended by the Board of Directors, thus there are no common unit distributions attributable to the fourth quarter 2015 or the third monthly payment of the distribution attributable to the third quarter. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Changes in accumulated other comprehensive income (loss) by component, net of tax, were as follows: Gain (loss) on Thousands of dollars Available-For-Sale Securities Pension and Postretirement Benefits Total Accumulated comprehensive loss as of December 31, 2013 $ — $ — $ — Amounts reclassified from accumulated other comprehensive loss (a) (189 ) (473 ) (662 ) Net current period other comprehensive loss (189 ) (473 ) (662 ) Accumulated comprehensive loss as of December 31, 2014 (189 ) (473 ) (662 ) Less: Accumulated comprehensive loss attributable to non-controlling interest (77 ) (193 ) (270 ) Accumulated comprehensive loss attributable to the Partnership as of December 31, 2014 (112 ) (280 ) (392 ) Other comprehensive (loss) income before reclassification (267 ) 677 410 Amounts reclassified from accumulated other comprehensive loss (a) (135 ) — (135 ) Net current period other comprehensive (loss) income (402 ) 677 275 Accumulated comprehensive (loss) income as of December 31, 2015 (514 ) 397 (117 ) Less: Accumulated comprehensive (loss) income attributable to non-controlling interest (164 ) 276 112 Accumulated comprehensive (loss) income attributable to the Partnership as of December 31, 2015 $ (350 ) $ 121 $ (229 ) (a) Amounts were reclassified from accumulated other comprehensive income (loss) to other expense (income), net on the consolidated statements of operations. |
Noncontrolling Interest
Noncontrolling Interest | 12 Months Ended |
Dec. 31, 2015 | |
Noncontrolling Interest [Abstract] | |
Noncontrolling Interest | Noncontrolling interest FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establish reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We have a 59% controlling interest in ETSWDC and have consolidated ETSWDC into our consolidated financial statements. The noncontrolling interest in ETSWDC at December 31, 2015 and 2014 was $7.3 million and $6.9 million , respectively. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields. |
Unit Based Compensation Plans
Unit Based Compensation Plans | 12 Months Ended |
Dec. 31, 2015 | |
Unit and Other Valuation Based Compensation Plans [Abstract] | |
Unit Based Compensation Plans | Unit Based Compensation Plans FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions . At December 31, 2015 , the RPUs and the CPUs granted to employees and directors under LTIP were all classified as equity awards. These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements. We recognized $26.8 million , $23.4 million and $20.0 million of compensation expense related to our various awards for the years ended December 31, 2015 , 2014 and 2013 , respectively. Unit-based compensation expense of $25.5 million was included in general and administrative expenses and $1.3 million was included in restructuring costs for the year ended December 31, 2015. See Note 21 for a discussion of restructuring costs. Restricted Phantom Units RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. Certain of our employees including our executives are eligible to receive RPU awards. RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment. The fair value of the RPUs is determined based on the fair market value of our units on the date of grant. RPU awards were granted to Breitburn Management employees during the years ended December 31, 2015 , 2014 and 2013 as shown in the table below. We recorded compensation expense of $20.2 million , $18.3 million and $17.0 million in 2015 , 2014 and 2013 , respectively, related to the amortization of outstanding RPUs over their related vesting periods. In connection with the workforce reduction (see Note 21), $1.3 million was recognized as restructuring costs for accelerated vesting of 0.1 million LTIP grants for certain individuals. As of December 31, 2015 , there was $23.3 million of total unrecognized compensation cost remaining for the unvested RPUs. This amount is expected to be recognized over the next two years. The total grant date fair value of units that vested during the years ended December 31, 2015 , 2014 and 2013 was $19.7 million , $18.4 million and $17.2 million , respectively. The following table summarizes information about RPUs: Year Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted of Average of Average of Average Thousands, except per unit amounts RPUs Fair Value RPUs Fair Value RPUs Fair Value Outstanding, beginning of period 957 $ 20.98 896 $ 21.05 817 $ 20.92 Granted 4,739 6.46 1,025 20.21 919 20.77 Vested (a) (2,012 ) 10.63 (906 ) 20.22 (833 ) 20.62 Canceled (646 ) 8.24 (58 ) 20.36 (7 ) 21.60 Outstanding, end of period 3,038 $ 7.90 957 $ 20.98 896 $ 21.05 (a) Includes 613 , 298 and 308 units canceled at the time of distribution for income tax liability payments we made on behalf of the restricted unit grantees for years ended December 31, 2015 , 2014 and 2013 , respectively. Convertible Phantom Units On January 28, 2013, the Compensation and Governance Committee approved grants to certain executives under the First Amended and Restated Partnership 2006 Long-Term Incentive Plan of CPUs in tandem with a corresponding Performance Distribution Right (“PDR”) which will remain outstanding from the Grant Date until the earlier to occur of a Payment Date or the forfeiture of the CPU to which such PDR corresponds. Each CPU granted was issued in tandem with a corresponding PDR, which entitles the Participant to receive an amount determined by reference to Partnership distributions and which will be credited to the Participant in the form of additional CPUs equal to the product of (i) the aggregate per Unit distributions paid by the Partnership in respect of each quarter through which the PDR remains outstanding (provided that the PDR is outstanding as of the record date set by the Board of Directors of the Company for such distribution) (including any extraordinary non-recurring distributions paid during a quarter), if any, times (ii) the number of common unit equivalents (“CUEs”) underlying the relevant CPU during such quarter, divided by the closing price of the Unit on the date on which such distribution is paid to Unitholders. All such PDRs will be credited to the Participant in the form of additional CPUs as of the date of payment of any such distribution based on the Fair Market Value of a Unit on such date. Each additional CPU which results from such crediting of PDRs granted hereunder will be subject to the same vesting, forfeiture, payment or distribution, adjustment and other provisions which apply to the underlying CPU to which such additional CPU relates. PDRs do not entitle the Participant to any amounts relating to distributions occurring after the earlier to occur of the applicable Payment Date or the Participant’s forfeiture of the CPU to which such PDR relates in accordance herewith. The CPUs will vest and the number of CUEs underlying such CPUs (if any) on the earliest to occur of (i) an applicable accelerated vesting date, and (ii) December 28, 2015, in each case subject to the Participant’s continued employment with the Partnership through any such date. CPUs that vest will represent the right to receive payment in the form of a number of Units equal to (i) the product of (A) the number of CPUs so vested, times (B) the number of CUEs underlying such CPUs on the applicable Vesting Date, minus (ii) the applicable number of PDR Equalization Units, if any (such number of Units, the “Resultant Units”). Unless and until a CPU vests, the Participant will have no right to payment of Units in respect of any such CPU. Prior to actual payment in respect of any vested CPU, such CPU will represent an unsecured obligation of the Partnership, payable (if at all) only from the general assets of the Partnership. On January 28, 2013, 0.3 million CPUs (“2013 CPUs”) were granted at a price of $20.98 per Common Unit and on January 29, 2014, an additional 0.3 million CPUs (“2014 CPUs”) were granted at a price of $20.29 per Common Unit. We recorded compensation expense for the 2013 and 2014 CPUs of approximately $4.3 million in each of the years 2015 and 2014. In 2013, we recorded $2.3 million to compensation expense for the 2013 CPUs. As of December 31, 2015 , the 2013 CPUs were fully vested and the 2014 CPUs remained unvested and outstanding with $2.0 million of unrecognized compensation cost remaining. On January 26, 2015, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements for grants made in 2013 and 2014. Prior to this amendment of the CPU Agreements, the number of CUEs per CPU over the three year life of the agreement could be reduced to a minimum of zero or be multiplied by a maximum of 4.768 times based on the Partnership’s distribution levels. The amendment to the CPU agreements, commencing with the date of the amendment, now limits the multiplier to “1.” As a result at vesting, CPUs for each award will convert to Common Units on a 1:1 basis. In addition, the amendment provided for the forfeiture from the date of grant to the date of the amendment of previously credited PDRs to each executive. No other modification was made to the CPU Agreements under this amendment. Director Restricted Phantom Units We have made grants of RPUs to the non-employee directors of our General Partner that are substantially similar to the ones granted to employees. The estimated fair value associated with these phantom units is expensed over the vesting period. We recorded compensation expense for the director’s phantom units of approximately $0.9 million , $0.8 million and $0.7 million in 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , there was $1.0 million of total unrecognized compensation cost for the unvested Director Restricted Phantom Units and such cost is expected to be recognized over the next two years. The following table summarizes information about the Director Restricted Phantom Units: Year Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted of Average of Average of Average Thousands, except per unit amounts Units Fair Value Units Fair Value Units Fair Value Outstanding, beginning of period 78 $ 20.44 67 $ 20.69 48 $ 20.43 Granted 160 6.56 43 20.29 38 20.98 Vested (37 ) 20.35 (32 ) 20.77 (19 ) 20.63 Outstanding, end of period 201 $ 9.42 78 $ 20.44 67 $ 20.69 |
Retirement Plan
Retirement Plan | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Retirement Plan | Retirement Plan Breitburn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of Breitburn Management. Breitburn Management has a defined contribution retirement plan, which covers substantially all of its employees commencing on the first day of the month following the month of hire. The plan provides for Breitburn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in Breitburn Management’s contributions after five years of service. PCEC is charged for a portion of the matching contributions made by Breitburn Management. For the years ended December 31, 2015 , 2014 and 2013 , we recognized expense related to matching contributions of $3.6 million , $3.7 million and $2.0 million , respectively. |
Significant Customers
Significant Customers | 12 Months Ended |
Dec. 31, 2015 | |
Risks and Uncertainties [Abstract] | |
Significant Customers | Significant Customers We sell oil, NGLs and natural gas primarily to large, established domestic refiners and utilities. For the years ended December 31, 2015 , 2014 and 2013 , sales of oil, NGL and natural gas production to each of the following purchasers represented 10% or more of total sales revenue: Year Ended December 31, 2015 2014 2013 Shell Trading 24 % 22 % 15 % Plains Marketing 12 % (a) (a) Phillips 66 (a) 10 % 15 % Marathon Oil Corporation (a) (a) 10 % (a) Represented less than 10% of total sales revenue for the respective year end. Our sales contracts are sold at market-sensitive or spot prices. Because commodity products are sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. As a result, the loss of any one purchaser would not have a long-term material adverse effect on our ability to sell our production. |
Restructuring Costs Restructuri
Restructuring Costs Restructuring Costs | 12 Months Ended |
Dec. 31, 2015 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Activities Disclosure [Text Block] | Restructuring Costs In the first quarter of 2015, we executed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees. In April 2015, we communicated further reductions to an additional 8 employees. For the year ended December 31, 2015, we recognized a total cost of $6.4 million , which included severance cash payments of $4.8 million , unit-based compensation of $1.3 million and other termination costs of $0.3 million . Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events On January 4, 2016 and January 28, 2016, we declared cash distributions for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on February 15, 2016 and March 15, 2016, respectively, to record holders of our Series A Preferred Units at the close of business on January 29, 2016 and February 29, 2016, respectively. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit. On January 4, 2016 and January 28, 2016 we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, payable on January 15, 2016 and February 15, 2016, respectively, to record holders of Series B Preferred Units at the close of business on December 31, 2015 and January 29, 2016, respectively. |
Summary of Significant Accoun31
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Principles of consolidation and basis of presentation | Principles of consolidation and basis of presentation The consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2015 and 2014 . These financial statements also include the results of our operations, our changes in comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2015 , 2014 , and 2013 . These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In addition, we assume realization of assets and settlement of liabilities in the normal course of business. We recognized net loss attributable to the partnership of $2.58 billion and cash provided by operations was $436.7 million for the year ended December 31, 2015 and had cash on hand of $10.5 million at December 31, 2015 . As of December 31, 2015, we had approximately $1.2 billion in borrowings under our credit facility, including $154 million classified as a current liability, and $25.8 million in letters of credit outstanding. Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria (see Note 9 for further discussion of our borrowing base). The borrowing base at December 31, 2015 was $1.8 billion and the next semi-annual redetermination is scheduled for April 2016. Based upon current commodity prices and other factors at the time of future redeterminations, we expect our borrowing base to be significantly decreased. Without a waiver from our lenders, our credit facility currently provides that if the borrowing base is reduced below our current outstanding borrowings, we are required to repay the deficiency in five equal monthly installments. Although our lenders have the discretion to redetermine the borrowing base below our current outstanding borrowings, we do not expect that to occur in April 2016. However, if commodity prices remain depressed or further decline, we expect our borrowing base to be reduced again at the subsequent borrowing base redetermination in October 2016, which could further impact and limit our liquidity. We believe our existing cash resources and hedge positions should provide us with sufficient funds to meet our expected working capital needs for 2016, assuming that our borrowing base is redetermined above our current outstanding borrowings. Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our credit facility will not reduce the borrowing base to an amount below our current outstanding borrowings in April or at the October 2016 redetermination or that our liquidity requirements will continue to be satisfied, given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the steep decline in commodity prices and the trading prices of our debt and equity securities, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in many cases, ceased to provide any new funding. We expect that we will take other actions to raise funds to repay debt, such as selling non-core assets or restructuring derivative contracts. |
Use of estimates | Use of estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, debt subject to acceleration, fair value of derivative instruments, unit-based compensation, pension and post-retirement obligations, future cash flow from oil, NGL and natural gas properties and oil, NGL and natural gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil, NGL and natural gas properties and goodwill. |
Business segment information | Business segment information We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas. |
Cash and cash equivalents | Cash and cash equivalents We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. Our cash and cash equivalents consist of cash in banks and investments in money market accounts. The majority of cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk. |
Accounts Receivable | Accounts receivable Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2015 and 2014 , we had an allowance for doubtful accounts receivable of $2.1 million and $1.6 million , respectively. |
Inventory | Inventory Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. When using lower of cost or market to value inventory, market is the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2015 and December 31, 2014 and we recognized write-downs of $0.6 million and $1.0 million , respectively. |
Property, plant and equipment | Property, plant and equipment Oil and natural gas properties We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred. We carry out tertiary recovery methods on certain of our oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO 2 , for enhanced oil recovery activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO 2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO 2 recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed. Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years. We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2015 , 2014 and 2013 , interest of $0.2 million , $0.3 million and $0.1 million , respectively, was capitalized and included in our capital expenditures. Non-oil and natural gas assets Buildings and non-oil and gas assets, including property and equipment related to the disposal of salt water at our East Texas fields, are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 25 years. |
Oil and natural gas reserve quantities | Oil and natural gas reserve quantities Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports. |
Investments | Investments Investments consist of debt and equity securities, all of which are classified as available-for-sale and stated at fair value on our consolidated balance sheet. Accordingly, unrecognized changes in fair value and the related deferred tax effect are excluded from earnings and reported as a separate component within our consolidated statement of other comprehensive income. Changes in fair value of securities sold are computed based on the specific identification of the securities sold, and are reclassified from other comprehensive income into earnings (reflected in other expense (income), net on the consolidated statements of operations) in the period sold. |
Pension and Other Postretirement Benefits | Pensions and Other Postretirement Benefits We recognize the overfunded or underfunded status of the pension and postretirement benefit plans as either assets or liabilities on our consolidated balance sheet. A plan’s funded status is the difference between the fair value of the plan assets and the plan’s benefit obligation. The plan’s benefit obligation is based on estimates using management’s best estimate and judgments which includes independent actuarial service assumptions to determine the plan obligation. We record the plan’s cost and income – unrecognized losses and gains, unrecognized prior service costs and credits and transition obligations, if any – in our consolidated statement of other comprehensive income until they are amortized into earnings as a component of benefit costs. |
Debt issuance costs | Debt issuance costs The costs incurred to obtain financing have been capitalized. Debt issuance costs are charged to interest expense over the term of the related debt instrument. With the implementation of Accounting Standards Update ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs , unamortized debt issuance costs associated with our outstanding Senior Notes (as defined below), which were formerly presented as a component of Other long-term assets, will be shown as a reduction to the carrying liability amount of our Senior Notes. |
Asset retirement obligations | Asset retirement obligations We have significant obligations to plug and abandon oil, natural gas and saltwater disposal wells and related equipment at the end of oil and natural gas production operations or salt water disposal operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. |
Revenue recognition | Revenue recognition We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As of December 31, 2015 and 2014 , our natural gas producer imbalance liability was $11.4 million and $11.5 million , respectively, reflected in other long-term liabilities on the consolidated balance sheets. |
Impairment of assets | Impairments Long-lived assets and finite lived intangible assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset or finite lived intangible asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset or finite lived intangible asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2% per year. Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the commodity price strip used where applicable. For impairment charges, the associated property’s expected future net cash flows were discounted using a long-term weighted average cost of capital which approximated 10% at December 31, 2015 . Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 6 for a discussion of impairments of oil, NGL and natural gas assets. We account for goodwill in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and charged to impairments. The analysis of the potential impairment of goodwill is a two step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment. Step two of the goodwill impairment test consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment. |
Equity-based compensation | Equity-based compensation Breitburn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 18. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is part of the general and administrative (“G&A”) expenses line on the consolidated statements of operations. We recognize equity-based compensation costs on a straight line basis over the requisite service periods. |
Fair market value of financial instruments | Fair market value of financial instruments The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 9 for the fair value of our Senior Notes. |
Accounting for business combinations | Accounting for business combinations We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets acquired and liabilities assumed are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. There was no goodwill recognized for 2015 acquisitions. We recognized $95.9 million of goodwill as part of the final purchase price related to the 2014 QRE Merger, which became fully impaired in 2015. |
Concentration of credit risk | Concentration of credit risk We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility, and we periodically monitor their credit ratings. For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of our crude oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows. |
Derivatives | Derivatives FASB Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. See Note 4 for detail on our derivative instruments. |
Income taxes | Income taxes Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided. We have three wholly-owned subsidiaries and a controlling interest in an additional subsidiary that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies. We performed an analysis as of December 31, 2015 and 2014 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. |
Net income or loss per unit | Net income or loss per unit FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Participating securities are not allocated losses in periods where net losses occur. Our 8.25% Series A Cumulative Redeemable Perpetual Preferred Units and 8.0% Series B Perpetual Convertible Preferred Units (collectively, the “Preferred Units”) rank senior to our Common Units with respect to the payment of distributions and, therefore, distributions on Preferred Units are deducted from net income when calculating net income attributable to common unitholders and participating securities. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation. |
Environmental expenditures | Environmental expenditures We review, on an annual basis and when new information becomes available, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At December 31, 2015 and 2014 , we had $0.6 million and $1.8 million undiscounted environmental liability accrued, respectively, that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. In December 2015, the environmental liability decreased by $1.2 million due to cost reductions to the estimated provision. |
Accounting Standards | Accounting Standards In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs . The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively. Early adoption is permitted. The adoption of these standards will not have an impact on our consolidated financial statements, other than balance sheet reclassifications. Under ASU 2015-03, the unamortized debt issuance costs of approximately $37.0 million as of December 31, 2015, associated with our outstanding Senior Notes, which were formerly presented as a component of Other Long Term Assets, will be shown as a reduction to the carrying liability amount of our Senior Notes. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . ASU 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These new requirements become effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. We are assessing the impact that ASU 2014-09 will have on our consolidated financial statements. In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis , which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We do not expect the adoption of this standard to have a material effect on our consolidated financial statements and related disclosures. In May 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per share (or Its Equivalent) , which permits a reporting entity, as a practical expedient, to measure the fair value of certain investments using the net asset value per share of the investment. Currently, investments valued using the practical expedient are categorized within the fair value hierarchy on the basis of whether the investment is redeemable with the investee at net asset value on the measurement date, never redeemable with the investee at net asset value, or redeemable with the investee at net asset value at a future date. For investments that are redeemable with the investee at a future date, a reporting entity must take into account the length of time until those investments become redeemable to determine the classification within the fair value hierarchy. The update is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of this standard to have a material effect on our consolidated financial statements and related disclosures. |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The final purchase price, for the 2014 QRE Merger, which was determined by management with the assistance of outside valuation consulting firms was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Cash $ 5,121 Accounts and other receivables 113,398 Current derivative instrument assets 70,362 Prepaid expenses 3,123 Oil and gas properties 2,397,967 Non-oil and gas assets 17,866 Goodwill 95,947 Long-term derivative instrument assets 72,998 Other long-term assets 50,619 Accounts payable and accrued liabilities (157,916 ) Current derivative instrument liabilities (6,512 ) Current asset retirement obligation (2,618 ) Credit facility debt (790,000 ) Senior notes at fair value (344,129 ) Long-term asset retirement obligation (91,465 ) Long-term derivative instrument liabilities (8,877 ) Other long-term liabilities (10,277 ) Non-controlling interest (7,173 ) $ 1,408,434 |
Business Acquisition, Pro Forma Information | Pro Forma Year Ended December 31, Thousands of dollars, except per unit amounts 2014 2013 Revenues $ 1,947,315 $ 1,280,718 Net income attributable to the partnership 541,935 102,486 Net income per common unit: Basic $ 2.51 $ 0.49 Diluted $ 2.50 $ 0.49 |
Oklahoma Panhandle - Whiting only [Domain] | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The final purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Oil and gas properties - proved $ 700,963 Oil and gas properties - unproved 43,492 Pipeline and processing facilities 74,537 Derivative assets - current 15 Intangibles 14,739 Derivative assets - long-term 16,183 Other long-term assets 10,936 Derivative liabilities - current (6,347 ) Accrued liabilities (1,115 ) Asset retirement obligation (8,102 ) $ 845,301 |
2013 Permian Basin Acquisitions [Member] | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The final purchase price for 2013 Permian Basin Acquisitions was allocated to the assets acquired and liabilities assumed as follows: Thousands of dollars Oil and gas properties - proved $ 258,728 Oil and gas properties - unproved 44,451 Asset retirement obligation $ (1,069 ) $ 302,110 |
Financial Instruments and Fai33
Financial Instruments and Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Delivery Commitments and Contracts [Line Items] | |
Prepaid Derivative Premiums | As of December 31, 2015 , premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2016 and beyond were as follows: Year Thousands of dollars 2016 2017 2018 2019 Oil $ 7,438 $ 734 $ — $ — Natural gas 952 — — — |
Schedule of Interest Rate Derivatives | We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at December 31, 2015 : Year 2016 2017 Fixed Rate Swaps - LIBOR Notional Amount (thousands of dollars) $ 710,000 $ 200,000 Average Fixed Rate 1.28 % 1.23 % |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | Fair value of derivative instruments not designated as hedging instruments: Balance sheet location, thousands of dollars Oil Commodity Derivatives Natural Gas Commodity Derivatives Interest Rate Derivatives Commodity Derivatives Netting (a) Total Financial Instruments As of December 31, 2015 Assets Current assets - derivative instruments $ 397,748 $ 44,426 $ 222 $ (2,769 ) $ 439,627 Other long-term assets - derivative instruments 202,140 27,105 216 (2,697 ) 226,764 Total assets 599,888 71,531 438 (5,466 ) 666,391 Liabilities Current liabilities - derivative instruments (15 ) (2,740 ) (4,476 ) 2,769 (4,462 ) Long-term liabilities - derivative instruments — (2,865 ) (87 ) 2,697 (255 ) Total liabilities (15 ) (5,605 ) (4,563 ) 5,466 (4,717 ) Net assets (liabilities) $ 599,873 $ 65,926 $ (4,125 ) $ — $ 661,674 As of December 31, 2014 Assets Current assets - derivative instruments $ 350,351 $ 58,246 $ — $ (445 ) $ 408,152 Other long-term assets - derivative instruments 296,441 29,649 210 (6,740 ) 319,560 Total assets 646,792 87,895 210 (7,185 ) 727,712 Liabilities Current liabilities - derivative instruments (214 ) (563 ) (5,126 ) 445 (5,458 ) Long-term liabilities - derivative instruments (1,520 ) (5,220 ) (2,269 ) 6,740 (2,269 ) Total liabilities (1,734 ) (5,783 ) (7,395 ) 7,185 (7,727 ) Net assets (liabilities) $ 645,058 $ 82,112 $ (7,185 ) $ — $ 719,985 (a) Represents counterparty netting under derivative netting agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These contracts are reflected net on the consolidated balance sheet. |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following table presents gains and losses on derivative instruments not designated as hedging instruments: Location of gain (loss), thousands of dollars Oil Commodity Derivatives (a) Natural Gas Commodity Derivatives (a) Interest Rate Derivatives (b) Total Financial Instruments Year Ended December 31, 2015 Net gain (loss) $ 385,887 $ 52,727 $ (2,691 ) $ 435,923 Year Ended December 31, 2014 Net gain $ 526,335 $ 40,198 $ 490 $ 567,023 Year Ended December 31, 2013 Net gain (loss) $ (34,259 ) $ 5,077 $ — $ (29,182 ) (a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. (b) Included in (gain) loss on interest rate swaps on the consolidated statements of operations |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table sets forth, by level within the hierarchy, the fair value of our financial instrument assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . All fair values reflected below and on the consolidated balance sheets have been adjusted for nonperformance risk. Thousands of dollars Level 1 Level 2 Level 3 Total As of December 31, 2015 Assets (liabilities) Oil derivative instruments Oil swaps $ — $ 552,552 $ — $ 552,552 Oil collars — — 29,737 29,737 Oil puts — — 17,584 17,584 Natural gas derivative instruments Natural gas swaps — 54,182 — 54,182 Natural gas collars — — 618 618 Natural gas puts — — 11,126 11,126 Interest rate swaps Interest rate swaps — (4,125 ) — (4,125 ) Available-for-sale securities Equities 2,524 — — 2,524 Mutual Funds 11,190 — — 11,190 Exchange traded funds 4,977 — — 4,977 Net assets $ 18,691 $ 602,609 $ 59,065 $ 680,365 As of December 31, 2014 Assets (liabilities) Oil derivative instruments Oil swaps $ — $ 583,648 $ — $ 583,648 Oil collars — — 44,405 44,405 Oil puts — — 17,005 17,005 Natural gas derivative instruments Natural gas swaps — 62,220 — 62,220 Natural gas collars — — 13,256 13,256 Natural gas puts — — 6,636 6,636 Interest rate swaps Interest rate swaps — (7,185 ) — (7,185 ) Available-for-sale securities Equities 4,138 — — 4,138 Mutual Funds 10,577 — — 10,577 Exchange traded funds 4,630 — — 4,630 Net assets $ 19,345 $ 638,683 $ 81,302 $ 739,330 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: Year End December 31, 2015 2014 2013 Thousands of dollars Oil Natural Gas Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 61,410 $ 19,892 $ 8,957 $ 1,848 $ 15,169 $ 1,672 Derivative instrument settlements (b) 44,647 16,815 4,094 815 (125 ) (892 ) Gain (loss) (b)(c) (58,736 ) (24,963 ) 37,189 5,357 (6,087 ) 1,068 Purchases (b)(d) — — 11,170 11,872 — — Ending balance $ 47,321 $ 11,744 $ 61,410 $ 19,892 $ 8,957 $ 1,848 (a) We had no fair value changes for our derivative instruments classified as Level 3 related to sales or issuances. (b) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. (c) Represents gain (loss) on mark-to-market of derivative instruments. (d) 2014 purchases related to derivative instruments novated to us in connection with the QRE Merger. |
Fair Value Inputs, Assets, Quantitative Information | For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2015 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars December 31, 2015 Technique Unobservable Input Range Oil options $ 47,321 Option Pricing Model Oil forward commodity prices $37.04/Bbl - $47.79/Bbl Oil volatility 32.24% - 44.95% Own credit risk 5% Natural gas options 11,744 Option Pricing Model Gas forward commodity prices $2.34/MMBtu - $2.99/MMBtu Gas volatility 23.44% - 73.05% Own credit risk 5% Total $ 59,065 For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2014 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars December 31, 2014 Technique Unobservable Input Range Oil options $ 61,410 Option pricing model Oil forward commodity prices $53.27/Bbl - $71.66/Bbl Oil volatility 29.21% - 46.16% Own credit risk 5% Natural gas options 19,892 Option pricing model Gas forward commodity prices $2.88/MMBtu - $3.99/MMBtu Gas volatility 18.59% - 63.51% Own credit risk 5% Total $ 81,302 |
Crude Oil [Member] | |
Oil and Gas Delivery Commitments and Contracts [Line Items] | |
Schedule of Price Risk Derivatives | We had the following oil contracts in place at December 31, 2015 : Year 2016 2017 2018 2019 Oil Positions: Fixed Price Swaps - NYMEX WTI Volume (Bbl/d) 17,504 14,519 1,493 1,000 Average Price ($/Bbl) $ 83.62 $ 82.81 $ 64.02 $ 56.35 Fixed Price Swaps - ICE Brent Volume (Bbl/d) 4,300 298 — — Average Price ($/Bbl) $ 95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d) 1,500 — — — Average Floor Price ($/Bbl) $ 80.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 102.00 $ — $ — $ — Collars - ICE Brent Volume (Bbl/d) 500 — — — Average Floor Price ($/Bbl) $ 90.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 101.25 $ — $ — $ — Puts - NYMEX WTI Volume (Bbl/d) 1,000 — — — Average Price ($/Bbl) $ 90.00 $ — $ — $ — Total: Volume (Bbl/d) 24,804 14,817 1,493 1,000 Average Price ($/Bbl) $ 85.79 $ 83.11 $ 64.02 $ 56.35 |
Natural Gas Commodity Derivatives [Member] | |
Oil and Gas Delivery Commitments and Contracts [Line Items] | |
Schedule of Price Risk Derivatives | We had the following natural gas contracts in place at December 31, 2015 : Year 2016 2017 2018 2019 Gas Positions: Fixed Price Swaps - MichCon City-Gate Volume (MMBtu/d) 29,000 24,000 17,500 10,000 Average Price ($/MMBtu) $ 3.91 $ 3.71 $ 3.10 $ 3.15 Fixed Price Swaps - Henry Hub Volume (MMBtu/d) 42,050 21,016 2,870 — Average Price ($/MMBtu) $ 4.02 $ 4.29 $ 3.74 $ — Collars - Henry Hub Hedged Volume (MMBtu/d) 630 595 — — Average Floor Price ($/MMBtu) $ 4.00 $ 4.00 $ — $ — Average Ceiling Price ($/MMBtu) $ 5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume (MMBtu/d) 11,350 10,445 — — Average Price ($/MMBtu) $ 4.00 $ 4.00 $ — $ — Deferred Premium ($/MMBtu) $ 0.66 (a) $ 0.69 (b) $ — $ — Total: Volume (MMBtu/d) 83,030 56,056 20,370 10,000 Average Price ($/MMBtu) $ 3.98 $ 3.98 $ 3.19 $ 3.15 |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Investments [Abstract] | |
Available-for-sale Securities | As of December 31, 2015 , we had the following available-for-sale investments outstanding: Gross Gross Thousands of dollars Cost Basis Unrealized Gains Unrealized Losses Fair Value Available-for-sale securities: Equities $ 2,591 $ 141 $ (208 ) $ 2,524 Mutual funds 13,276 1,737 (3,823 ) 11,190 Exchange traded funds 3,721 1,494 (238 ) 4,977 Total available-for-sale securities $ 19,588 $ 3,372 $ (4,269 ) $ 18,691 As of December 31, 2014 , we had the following available-for-sale investments outstanding: Gross Gross Thousands of dollars Cost Basis Unrealized Gains Unrealized Losses Fair Value Available-for-sale securities: Equities $ 4,203 $ 92 $ (157 ) $ 4,138 Mutual funds 10,623 20 (66 ) 10,577 Exchange traded funds 4,808 27 (205 ) 4,630 Total available-for-sale securities $ 19,634 $ 139 $ (428 ) $ 19,345 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Instrument [Line Items] | |
Schedule of Long-term Debt Instruments | Our long-term debt is detailed in the following table: As of December 31, Thousands of dollars 2015 2014 Credit facility $ 1,229,000 $ 2,194,500 Promissory note 2,938 1,100 9.25% Senior Secured Notes due 2020 650,000 — 8.625% Senior Unsecured Notes due 2020 305,000 305,000 7.875% Senior Unsecured Notes due 2022 850,000 850,000 Net (discount) premium on Senior Notes (15,781 ) 1,560 Total debt 3,021,157 3,352,160 Less: Current portion of long-term debt (154,000 ) (105,000 ) Total long-term debt $ 2,867,157 $ 3,247,160 |
Schedule of Interest Expense | Our interest expense is detailed in the following table: Year Ended December 31, Thousands of dollars 2015 2014 2013 Credit facility (including commitment fees) $ 41,254 $ 23,788 $ 15,698 Senior Secured Notes 43,758 — — Senior Unsecured Notes 93,244 95,662 65,068 Amortization of discount/premium and deferred issuance costs (a) 24,926 7,836 6,429 Capitalized interest (155 ) (326 ) (128 ) Total $ 203,027 $ 126,960 $ 87,067 Cash paid for interest $ 181,873 $ 119,488 $ 74,078 (a) The year ended December 31, 2015 included a write-off of $10.6 million of debt issuance costs related to the reduction of our credit facility borrowing base. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following: Year Ended December 31, Thousands of dollars 2015 2014 2013 Federal income tax expense (benefit) Current $ 626 $ 212 $ 472 Deferred (a) 784 (173 ) 262 Current state income tax expense (benefit) (b) 117 (112 ) 171 Total $ 1,527 $ (73 ) $ 905 (a) Related to Phoenix and Breitburn Management, our wholly-owned subsidiaries, and ETSWDC, a subsidiary we have a controlling interest in. (b) Primarily in California and Texas. |
Schedule of Deferred Tax Assets and Liabilities | ignificant components of our net deferred tax liabilities are presented in the following table: December 31, Thousands of dollars 2015 2014 Deferred tax assets: Asset retirement obligation $ 2,296 $ 2,120 Operating loss carryforwards 3,714 2,341 Unused minimum tax credit — 440 Compensation accruals 1,558 1,315 Pension costs 1,724 2,461 Post-retirement costs 823 952 Other 309 103 Valuation allowance (6,542 ) (4,243 ) Deferred tax liabilities: Depreciation, depletion and intangible drilling costs (6,505 ) (6,455 ) Unrealized hedge gain (825 ) (1,069 ) Net deferred tax liability $ (3,448 ) $ (2,035 ) |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Changes in ARO for the years ended December 31, 2015 and 2014 , are presented in the following table: Year Ended December 31, Thousands of dollars 2015 2014 Carrying amount, beginning of period $ 238,411 $ 123,769 Liabilities added from acquisitions 796 95,800 Liabilities incurred from drilling 2,268 4,020 Liabilities settled (7,744 ) (1,708 ) Liabilities related to divested properties (261 ) — Revision of estimates 3,954 6,770 Accretion expense 16,954 9,760 Carrying amount, end of period 254,378 238,411 Less: Current portion of ARO (2,341 ) (4,948 ) Non-current portion of ARO $ 252,037 $ 233,463 |
Pension and Postretirement Be38
Pension and Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Pension and Postretirement Benefits [Line Items] | |
Schedule of Accumulated and Projected Benefit Obligations | The Plans had accumulated benefit obligations in excess of plan assets at December 31, 2015 and 2014 as follows: December 31, 2015 December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Projected benefit obligation $ 25,320 $ 3,971 27,829 4,240 Accumulated benefit obligation 24,424 3,971 26,872 4,240 Fair value of plan assets 20,022 1,468 21,219 1,527 |
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan | The change in the combined projected benefit obligation of the Plans and the change in the assets at fair value are as follows: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Change in Benefit Obligation Benefit obligation at beginning of year $ 27,829 $ 4,240 $ — $ — 2014 Acquisition of ETSWDC — — 27,300 4,144 Service cost 271 34 33 4 Interest cost 1,014 155 120 18 Plan participant contributions — 28 — 2 Actuarial (gain) loss (2,360 ) (333 ) 496 85 Benefits paid (1,434 ) (153 ) (120 ) (13 ) Benefit obligation at end of year 25,320 3,971 27,829 4,240 Change in Plan Assets Fair value of plan assets at beginning of year 21,219 1,527 — — 2014 Acquisition of ETSWDC — — 21,319 1,518 Actual return on plan assets (163 ) (63 ) 20 9 Employer contributions 400 129 — 11 Plan participant contributions — 28 — 2 Benefits paid (1,434 ) (153 ) (120 ) (13 ) Fair value of plan assets at end of year 20,022 1,468 21,219 1,527 Underfunded status at end of year $ (5,298 ) $ (2,503 ) (6,610 ) (2,713 ) |
Schedule of Amounts Recognized in Balance Sheet | Amounts recognized on the consolidated balance sheet at December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Long-term liabilities 5,298 2,503 6,610 2,713 |
Schedule of Net Benefit Costs | Net periodic benefit costs recognized on the consolidated statements of operations for the years ended December 31, 2015 and 2014 consist of the following: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Service cost $ 271 $ 34 $ 33 $ 4 Interest cost 1,014 155 120 18 Expected return on plan assets (1,342 ) (99 ) (152 ) (11 ) Net periodic benefit costs $ (57 ) $ 90 $ 1 $ 11 |
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) | Amounts recognized in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 consist of the following: Year Ended December 31, 2015 Year Ended December 31, 2014 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Prior service cost $ — $ — $ — $ — Net actuarial (gain) loss: Liability (gain) loss due to assumption change (2,045 ) (220 ) 474 88 Liability (gain) loss due to participant experience (315 ) (113 ) 22 (3 ) Asset return loss 1,505 162 132 3 Net actuarial (gain) loss (855 ) (171 ) 628 88 Total $ (855 ) $ (171 ) $ 628 $ 88 |
Schedule of Expected Benefit Payments | As of December 31, 2015 the following estimated benefit payments under the Plans, which reflect expected future service, as appropriate, are expected to be paid as follows: Thousands of dollars Pension Benefits Postretirement Benefits 2016 $ 1,500 $ 150 2017 1,510 170 2018 1,540 190 2019 1,580 210 2020 1,650 230 2021-2025 8,620 1,060 |
Projected Postretirement Benefit Obligations And Postretirement Costs [Member] | |
Pension and Postretirement Benefits [Line Items] | |
Schedule of Assumptions Used | Assumptions used to determine the Plans’ projected benefit obligations and costs as of December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Discount rate 4.10 % 4.10 % 3.75 % 3.75 % Rate of compensation increase 3.00 % N/A 3.00 % N/A Health care cost trend rate: Pre - 65 rate N/A 7.00 % N/A 7.00 % Post - 65 rate N/A 7.00 % N/A 6.00 % Expected long-term rates of return on plan assets 6.75 % 6.75 % 6.50 % 6.50 % Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A 4.5 % N/A 4.5 % Year that the rate reaches the ultimate trend rate N/A 2023 N/A 2022 |
Net Periodic Benefit Costs [Member] | |
Pension and Postretirement Benefits [Line Items] | |
Schedule of Assumptions Used | Assumptions used to determine net periodic benefit costs for the years ended December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Discount rate 3.75 % 3.75 % 3.90 % 3.75 % Expected long-term return on plan assets 6.50 % 6.50 % 6.50 % 6.50 % Rate of compensation increase 3.00 % N/A 3.00 % N/A |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | Our future minimum rental payments for operating leases at December 31, 2015 are presented below: Payments Due by Year Thousands of dollars 2016 2017 2018 2019 2020 Thereafter Total Operating leases $ 11,368 $ 11,323 $ 7,037 $ 5,615 $ 5,648 $ 14,480 $ 55,471 |
Partners' Equity (Tables)
Partners' Equity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Partners' Capital [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit. Year Ended December 31, Thousands, except per unit amounts 2015 2014 2013 Net (loss) income attributable to the partnership $ (2,583,339 ) $ 421,333 $ (43,671 ) Less: Net income (loss) attributable to participating units — 5,348 — Distributions on participating units in excess of earnings 1,731 — — Distributions to Series A preferred unitholders 16,500 10,083 — Non-cash distributions to Series B preferred unitholders 20,817 — — Net (loss) income used to calculate basic and diluted net (loss) income per unit $ (2,622,387 ) $ 405,902 $ (43,671 ) Weighted average number of units used to calculate basic and diluted net income (loss) per unit: Common Units 211,575 133,451 101,604 Dilutive units (a) — 755 — Denominator for diluted net (loss) income per unit 211,575 134,206 101,604 Net (loss) income per common unit Basic $ (12.39 ) $ 3.04 $ (0.43 ) Diluted $ (12.39 ) $ 3.02 $ (0.43 ) (a) The years ended December 31, 2015 and December 31, 2013 exclude 725 and 364 weighted average anti-dilutive units, respectively, from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. |
Accumulated Other Comprehensi41
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Changes in accumulated other comprehensive income (loss) by component, net of tax, were as follows: Gain (loss) on Thousands of dollars Available-For-Sale Securities Pension and Postretirement Benefits Total Accumulated comprehensive loss as of December 31, 2013 $ — $ — $ — Amounts reclassified from accumulated other comprehensive loss (a) (189 ) (473 ) (662 ) Net current period other comprehensive loss (189 ) (473 ) (662 ) Accumulated comprehensive loss as of December 31, 2014 (189 ) (473 ) (662 ) Less: Accumulated comprehensive loss attributable to non-controlling interest (77 ) (193 ) (270 ) Accumulated comprehensive loss attributable to the Partnership as of December 31, 2014 (112 ) (280 ) (392 ) Other comprehensive (loss) income before reclassification (267 ) 677 410 Amounts reclassified from accumulated other comprehensive loss (a) (135 ) — (135 ) Net current period other comprehensive (loss) income (402 ) 677 275 Accumulated comprehensive (loss) income as of December 31, 2015 (514 ) 397 (117 ) Less: Accumulated comprehensive (loss) income attributable to non-controlling interest (164 ) 276 112 Accumulated comprehensive (loss) income attributable to the Partnership as of December 31, 2015 $ (350 ) $ 121 $ (229 ) (a) Amounts were reclassified from accumulated other comprehensive income (loss) to other expense (income), net on the consolidated statements of operations. |
Unit Based Compensation Plans (
Unit Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Restricted Phantom Units (RPUs) [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | The following table summarizes information about RPUs: Year Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted of Average of Average of Average Thousands, except per unit amounts RPUs Fair Value RPUs Fair Value RPUs Fair Value Outstanding, beginning of period 957 $ 20.98 896 $ 21.05 817 $ 20.92 Granted 4,739 6.46 1,025 20.21 919 20.77 Vested (a) (2,012 ) 10.63 (906 ) 20.22 (833 ) 20.62 Canceled (646 ) 8.24 (58 ) 20.36 (7 ) 21.60 Outstanding, end of period 3,038 $ 7.90 957 $ 20.98 896 $ 21.05 (a) Includes 613 , 298 and 308 units canceled at the time of distribution for income tax liability payments we made on behalf of the restricted unit grantees for years ended December 31, 2015 , 2014 and 2013 , respectively. |
Director Restricted Phantom Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | The following table summarizes information about the Director Restricted Phantom Units: Year Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted of Average of Average of Average Thousands, except per unit amounts Units Fair Value Units Fair Value Units Fair Value Outstanding, beginning of period 78 $ 20.44 67 $ 20.69 48 $ 20.43 Granted 160 6.56 43 20.29 38 20.98 Vested (37 ) 20.35 (32 ) 20.77 (19 ) 20.63 Outstanding, end of period 201 $ 9.42 78 $ 20.44 67 $ 20.69 |
Significant Customers Significa
Significant Customers Significant Customers (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Risks and Uncertainties [Abstract] | |
Schedules of Concentration of Risk, by Risk Factor | For the years ended December 31, 2015 , 2014 and 2013 , sales of oil, NGL and natural gas production to each of the following purchasers represented 10% or more of total sales revenue: Year Ended December 31, 2015 2014 2013 Shell Trading 24 % 22 % 15 % Plains Marketing 12 % (a) (a) Phillips 66 (a) 10 % 15 % Marathon Oil Corporation (a) (a) 10 % (a) Represented less than 10% of total sales revenue for the respective year end. |
Organization (Details)
Organization (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Business Acquisition [Line Items] | ||
Business Acquisition, Effective Date of Acquisition | Nov. 19, 2014 | |
General Partner [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
Breitburn Operating LP [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
Breitburn Management Company LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
Breitburn Finance Corporation [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
Breitburn Collingwood Utica LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | |
QR Energy LP [Member] | ||
Business Acquisition [Line Items] | ||
Equity ownership percentage | 100.00% |
Summary of Significant Accoun45
Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | May. 21, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Nov. 19, 2014 |
Unamortized Debt Issuance Expense | $ 37,000 | ||||
Inventory Adjustments | 600 | $ 1,000 | |||
Preferred Stock, Dividend Rate, Percentage | 8.25% | ||||
Gas Balancing Asset (Liability) | $ 11,400 | 11,500 | |||
Equity basis, ownership percentage | 20.00% | ||||
Cost basis, ownership percentage | 20.00% | ||||
Consolidated, ownership percentage | 50.00% | ||||
Consolidated, controlling or variable interest, ownership percentage | 50.00% | ||||
Net income (loss) | $ (2,583,339) | 421,333 | $ (43,671) | ||
Net Cash Provided by (Used in) Operating Activities | 436,705 | 357,755 | 257,166 | ||
Allowance for Doubtful Accounts Receivable, Current | 2,100 | 1,600 | |||
Interest costs, capitalized during period | $ 155 | 326 | $ 128 | ||
Percentage Rate Of Escalation, Impairment Of Assets | 2.00% | ||||
Discount Rate, Future Net Revenues for Estimated Proved Reserves | 10.00% | ||||
Period of Time, Finalization of Purchase Price Allocations from Acquisition Date, Maximum | 1 year | ||||
Accrued environmental loss contingencies | $ 600 | 1,800 | |||
Cash | 10,464 | 12,628 | |||
Credit facility debt | 1,229,000 | 2,194,500 | |||
Letters of Credit Outstanding, Amount | 25,800 | 26,500 | |||
Line of Credit Facility, Current Borrowing Capacity | 1,800,000 | 2,500,000 | |||
Goodwill | 0 | 92,024 | |||
Current portion of long-term debt (note 9) | 154,000 | 105,000 | |||
Equity investments | 6,567 | $ 6,463 | |||
Commitment from existing lenders, borrowing base | 1,800,000 | ||||
Other Increase (Decrease) in Environmental Liabilities | $ (1,200) | ||||
Minimum [Member] | |||||
Property, plant and equipment, useful life, average (in years) | 3 years | ||||
Maximum [Member] | |||||
Property, plant and equipment, useful life, average (in years) | 25 years | ||||
Support Equipment and Facilities [Member] | |||||
Property, plant and equipment, useful life, average (in years) | 20 years | ||||
CO2 Assets [Member] | |||||
Property, plant and equipment, useful life, average (in years) | 40 years | ||||
Natural Gas [Member] | |||||
Period that receivables are collected within (in days) | 60 days | ||||
Crude Oil [Member] | |||||
Period that receivables are collected within (in days) | 30 days | ||||
QR Energy LP [Member] | |||||
Consolidated, controlling or variable interest, ownership percentage | 59.00% | ||||
Credit facility debt | $ 790,000 | ||||
Goodwill | $ 95,947 |
Acquisitions - Narrative (Detai
Acquisitions - Narrative (Details) $ in Thousands, bbl in Millions | Nov. 19, 2014USD ($)shares | Sep. 30, 2015USD ($) | Aug. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Nov. 30, 2014shares | Oct. 31, 2014USD ($)shares | Jul. 31, 2013USD ($) | Dec. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014shares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($)contract | Dec. 31, 2014USD ($) | Jun. 30, 2015USD ($) | May. 31, 2015USD ($) | Oct. 24, 2014USD ($) | Dec. 30, 2013USD ($) | Jul. 15, 2013USD ($)bbl$ / bbl | Oct. 06, 2010USD ($) |
Business Acquisition [Line Items] | |||||||||||||||||||||
Non-oil and gas assets | $ 6,454,201 | $ 3,932,882 | $ 6,454,201 | $ 3,932,882 | $ 6,454,201 | $ 6,454,201 | |||||||||||||||
Asset Retirement Obligation | 238,411 | $ 254,378 | $ 238,411 | $ 254,378 | $ 238,411 | $ 123,769 | 238,411 | ||||||||||||||
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed | 35.00% | ||||||||||||||||||||
CO2 Purchase Contract | 2 | ||||||||||||||||||||
Discount Rate, Future Net Revenues for Estimated Proved Reserves | 10.00% | ||||||||||||||||||||
Consolidated, controlling or variable interest, ownership percentage | 50.00% | 50.00% | |||||||||||||||||||
Senior notes at fair value | 0 | $ 650,000 | $ 0 | $ 650,000 | $ 0 | 0 | |||||||||||||||
Other long-term assets | 165,378 | 117,872 | 165,378 | 117,872 | 165,378 | 165,378 | |||||||||||||||
Asset retirement obligation (note 12) | $ 233,463 | 252,037 | $ 233,463 | 252,037 | 233,463 | $ 233,463 | |||||||||||||||
CO2 Assets [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Non-oil and gas assets | 70,500 | $ 70,500 | |||||||||||||||||||
Payments to Acquire Businesses, Net of Cash Acquired | $ 600 | $ 13,700 | $ 49,900 | ||||||||||||||||||
Intangible Assets, Net (Excluding Goodwill) | $ 5,100 | ||||||||||||||||||||
Asset retirement obligation (note 12) | $ 300 | ||||||||||||||||||||
QR Energy LP [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Non-oil and gas assets | $ 17,866 | ||||||||||||||||||||
Conversion of Stock, Shares Issued | shares | 0.9856 | ||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,748,067 | 6,133,558 | |||||||||||||||||||
Common units issued during acquisition | shares | 71,500,000 | ||||||||||||||||||||
Consolidated, controlling or variable interest, ownership percentage | 59.00% | 59.00% | 59.00% | 59.00% | |||||||||||||||||
Business Combination, Acquisition Related Costs | $ 11,800 | ||||||||||||||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | $ 42,100 | ||||||||||||||||||||
Business Combination, Operating Expense of Acquiree since Acquisition Date, Actual | 24,900 | ||||||||||||||||||||
Debt Instrument, Unamortized Discount | $ 3,000 | ||||||||||||||||||||
Senior notes at fair value | 344,129 | ||||||||||||||||||||
Other long-term assets | 50,619 | ||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | 1,408,434 | ||||||||||||||||||||
Oil and gas properties | 2,397,967 | ||||||||||||||||||||
Asset retirement obligation (note 12) | 91,465 | ||||||||||||||||||||
Property ownership interest | 100.00% | 100.00% | |||||||||||||||||||
Oklahoma Panhandle - Others [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Purchase price | $ 30,000 | ||||||||||||||||||||
Oil and gas properties | $ 17,800 | ||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 12,400 | ||||||||||||||||||||
Oklahoma Panhandle [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business Combination, Acquisition Related Costs | 3,200 | $ 3,300 | |||||||||||||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 104,900 | ||||||||||||||||||||
Business Combination, Operating Expense of Acquiree since Acquisition Date, Actual | 29,900 | ||||||||||||||||||||
2013 Permian Basin Acquisitions-CrownRock [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Purchase price | $ 282,000 | ||||||||||||||||||||
2013 Permian Basin Acquisitions-Others [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Purchase price | 20,000 | ||||||||||||||||||||
2013 Permian Basin Acquisitions [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business Combination, Acquisition Related Costs | 600 | 100 | |||||||||||||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 200 | ||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 302,110 | ||||||||||||||||||||
Asset retirement obligation (note 12) | $ 1,069 | ||||||||||||||||||||
Antares [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Common units issued during acquisition | shares | 4,300,000 | ||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 122,300 | $ 50,000 | |||||||||||||||||||
Oklahoma Panhandle - Whiting only [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Non-oil and gas assets | 74,537 | ||||||||||||||||||||
Derivative assets - current | 14,739 | ||||||||||||||||||||
Other long-term assets | 10,936 | ||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | 845,301 | ||||||||||||||||||||
Asset retirement obligation (note 12) | 8,102 | ||||||||||||||||||||
Whiting [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Derivative assets - current | $ 14,700 | 14,700 | |||||||||||||||||||
CO2 Purchase Contract | contract | 2 | ||||||||||||||||||||
Amortization of Intangible Assets | $ 2,200 | 3,900 | $ 3,600 | ||||||||||||||||||
Ark-La-Tex [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 3,000 | ||||||||||||||||||||
Kingfisher County, Oklahoma [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business Combination, Consideration Transferred | $ 3,600 | ||||||||||||||||||||
Nonmonetary Transaction, Gain (Loss) Recognized on Transfer | $ 3,200 | ||||||||||||||||||||
Property ownership interest | 0.00% | ||||||||||||||||||||
Weld County, Colorado [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business Combination, Consideration Transferred | $ 4,800 | ||||||||||||||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain | $ 7,800 | ||||||||||||||||||||
Unproved [Member] | Antares [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | 110,900 | ||||||||||||||||||||
Proved [Member] | Antares [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 13,100 | ||||||||||||||||||||
Senior Notes due 2020 | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.625% | ||||||||||||||||||||
Debt Instrument, Face Amount | 305,000 | $ 305,000 | 305,000 | 305,000 | 305,000 | 305,000 | |||||||||||||||
Subordinated Long-term Debt, Noncurrent | 302,100 | 302,100 | 302,100 | 302,100 | 302,100 | 302,100 | $ 300,000 | ||||||||||||||
Debt Instrument, Unamortized Discount | $ 2,900 | $ 2,900 | $ 2,900 | $ 2,900 | $ 2,900 | $ 2,900 | $ 5,000 | ||||||||||||||
Senior Notes due 2020 | QR Energy LP [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Subordinated Long-term Debt, Noncurrent | 297,000 | ||||||||||||||||||||
Senior Notes [Member] | QR Energy LP [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Debt Instrument, Face Amount | $ 300,000 | ||||||||||||||||||||
Crude Oil [Member] | Oklahoma Panhandle - Whiting only [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Derivative, Fair Value, Net | $ 9,900 | ||||||||||||||||||||
NYMEX WTI [Member] | Swap [Member] | Crude Oil [Member] | Term of Calendar 2013-2016 [Member] | Oklahoma Panhandle - Whiting only [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Derivative, Nonmonetary Notional Amount | bbl | 5.4 | ||||||||||||||||||||
NYMEX WTI [Member] | Swap [Member] | Crude Oil [Member] | Term of Calendar 2013 [Member] | Oklahoma Panhandle - Whiting only [Domain] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 95.44 | ||||||||||||||||||||
First Tranche [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed | 109.25% | ||||||||||||||||||||
Second Tranche [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed | 117.67% |
Acquisitions - Purchase Price A
Acquisitions - Purchase Price Allocation (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Nov. 30, 2014 | Jul. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2015 | Nov. 19, 2014 | Oct. 31, 2014 | Oct. 24, 2014 | Dec. 31, 2013 | Dec. 30, 2013 | Jul. 15, 2013 | Dec. 31, 2012 | |
Business Acquisition [Line Items] | ||||||||||||
Cash | $ 12,628 | $ 12,628 | $ 10,464 | $ 2,458 | $ 4,507 | |||||||
Current derivative instrument assets | 408,151 | 408,151 | 439,627 | |||||||||
Non-oil and gas assets | 6,454,201 | 6,454,201 | 3,932,882 | |||||||||
Goodwill | 92,024 | 92,024 | 0 | |||||||||
Long-term derivative instrument assets | 319,560 | 319,560 | 226,764 | |||||||||
Other long-term assets | 165,378 | 165,378 | 117,872 | |||||||||
Current derivative instrument liabilities | 5,457 | 5,457 | 4,462 | |||||||||
Other current liabilities | 7,495 | 7,495 | 5,133 | |||||||||
Current asset retirement obligation | 4,948 | 4,948 | 2,341 | |||||||||
Credit facility debt | 2,194,500 | 2,194,500 | 1,229,000 | |||||||||
Senior notes at fair value | 0 | 0 | 650,000 | |||||||||
Long-term asset retirement obligation | (233,463) | (233,463) | (252,037) | |||||||||
Long-term derivative instrument liabilities | 2,269 | 2,269 | 255 | |||||||||
Other long-term liabilities | 25,135 | 25,135 | 25,218 | |||||||||
Asset Retirement Obligation | 238,411 | $ 238,411 | $ 254,378 | $ 123,769 | ||||||||
QR Energy LP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cash | $ 5,121 | |||||||||||
Accounts and other receivables | 113,398 | |||||||||||
Current derivative instrument assets | 70,362 | |||||||||||
Prepaid expenses | 3,123 | |||||||||||
Oil and gas properties | 2,397,967 | |||||||||||
Non-oil and gas assets | 17,866 | |||||||||||
Goodwill | 95,947 | |||||||||||
Long-term derivative instrument assets | 72,998 | |||||||||||
Other long-term assets | 50,619 | |||||||||||
Accounts payable and accrued liabilities | 157,916 | |||||||||||
Current derivative instrument liabilities | 6,512 | |||||||||||
Current asset retirement obligation | 2,618 | |||||||||||
Credit facility debt | 790,000 | |||||||||||
Senior notes at fair value | 344,129 | |||||||||||
Long-term asset retirement obligation | (91,465) | |||||||||||
Long-term derivative instrument liabilities | 8,877 | |||||||||||
Other long-term liabilities | 10,277 | |||||||||||
Non-controlling interest | 7,173 | |||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 1,408,434 | |||||||||||
Antares [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 122,300 | $ 50,000 | ||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligations | $ 1,700 | |||||||||||
Oklahoma Panhandle - Whiting only [Domain] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Oil and gas properties - proved | $ 700,963 | |||||||||||
Oil and gas properties - unproved | 43,492 | |||||||||||
Current derivative instrument assets | 15 | |||||||||||
Derivative assets - current | 14,739 | |||||||||||
Non-oil and gas assets | 74,537 | |||||||||||
Long-term derivative instrument assets | 16,183 | |||||||||||
Other long-term assets | 10,936 | |||||||||||
Current derivative instrument liabilities | 6,347 | |||||||||||
Other current liabilities | 1,115 | |||||||||||
Long-term asset retirement obligation | (8,102) | |||||||||||
Assets Acquired and Liabilities Assumed, Net | 845,301 | |||||||||||
2013 Permian Basin Acquisitions-Others [Domain] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Period Results Included in Combined Entity | 2 days | |||||||||||
Payments to Acquire Businesses, Gross | 20,000 | |||||||||||
Permian Basin III (Dec. 30, 2013) [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Oil and gas properties - proved | $ 258,728 | |||||||||||
Oil and gas properties - unproved | 44,451 | |||||||||||
Long-term asset retirement obligation | (1,069) | |||||||||||
Assets Acquired and Liabilities Assumed, Net | $ 302,110 | |||||||||||
2013 Permian Basin Acquisitions-CrownRock [Domain] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Payments to Acquire Businesses, Gross | $ 282,000 | |||||||||||
Oklahoma Panhandle - Others [Domain] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Payments to Acquire Businesses, Gross | $ 30,000 | |||||||||||
Oil and gas properties | $ 17,800 | |||||||||||
Common Class C [Member] | QR Energy LP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cash Paid to Acquiree Unitholders | $ 350,000 |
Acquisitions - Pro Forma (Detai
Acquisitions - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Combinations [Abstract] | ||
Percentage of total revenue | 0.10% | |
Revenues | $ 1,947,315 | $ 1,280,718 |
Net income attributable to the partnership | $ 541,935 | $ 102,486 |
Basic | $ 2.51 | $ 0.49 |
Diluted | $ 2.50 | $ 0.49 |
Financial Instruments and Fai49
Financial Instruments and Fair Value Measurements - Narrative (Details) - Credit Concentration Risk [Member] - Derivative Financial Instruments, Assets [Member] | 12 Months Ended |
Dec. 31, 2015 | |
Well Fargo Bank National Association [Member] | |
Derivative [Line Items] | |
Concentration Risk, Percentage | 15.00% |
Barclays Bank PLC [Member] | |
Derivative [Line Items] | |
Concentration Risk, Percentage | 13.00% |
Credit Suisse [Member] | |
Derivative [Line Items] | |
Concentration Risk, Percentage | 11.00% |
Morgan Stanley Capital Group Inc [Member] | |
Derivative [Line Items] | |
Concentration Risk, Percentage | 11.00% |
Financial Instruments and Fai50
Financial Instruments and Fair Value Measurements - Oil and Natural Gas Contracts (Details) $ in Thousands | Dec. 31, 2015USD ($)bbl / DaysEnergy / Days$ / Energy$ / bbl |
Oil (NYMEX WTI) [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | 85.79 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 24,804 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | 83.11 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 14,817 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | 64.02 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,493 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | 56.35 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,000 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 83.62 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 17,504 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 82.81 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 14,519 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 64.02 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,493 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 56.35 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,000 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 80 |
Derivative, Average ceiling price | 102 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,500 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl / Days | 1,000 |
Derivative, Average Price Risk Option Strike Price | 90 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
Derivative, Average Price Risk Option Strike Price | 0 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
Derivative, Average Price Risk Option Strike Price | 0 |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
Derivative, Average Price Risk Option Strike Price | 0 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 95.17 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 4,300 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 97.50 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 298 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 90 |
Derivative, Average ceiling price | 101.25 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 500 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | 0 |
Derivative, Average ceiling price | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
Henry Hub [Member] | Natural Gas [Member] | Collars [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | $ / Energy | 4 |
Derivative, Average ceiling price | $ / Energy | 5.55 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 630 |
Henry Hub [Member] | Natural Gas [Member] | Collars [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | $ / Energy | 4 |
Derivative, Average ceiling price | $ / Energy | 6.15 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 595 |
Henry Hub [Member] | Natural Gas [Member] | Collars [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | $ / Energy | 0 |
Derivative, Average ceiling price | $ / Energy | 0 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 |
Henry Hub [Member] | Natural Gas [Member] | Collars [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Average Floor Price | $ / Energy | 0 |
Derivative, Average ceiling price | $ / Energy | 0 |
Derivative, Nonmonetary Notional Amount | bbl / Days | 0 |
Natural Gas [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | $ 952 |
Natural Gas [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 0 |
Natural Gas [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 0 |
Natural Gas [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 0 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 7,438 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 734 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | 0 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Prepaid Derivative Premium | $ | $ 0 |
Natural Gas [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | $ / Energy | 3.98 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 83,030 |
Natural Gas [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | $ / Energy | 3.98 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 56,056 |
Natural Gas [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | $ / Energy | 3.19 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 20,370 |
Natural Gas [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Average Forward Price | $ / Energy | 3.15 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 10,000 |
Natural Gas [Member] | Mich Con City-Gate [Member] | Swap [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.91 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 29,000 |
Natural Gas [Member] | Mich Con City-Gate [Member] | Swap [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.71 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 24,000 |
Natural Gas [Member] | Mich Con City-Gate [Member] | Swap [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.10 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 17,500 |
Natural Gas [Member] | Mich Con City-Gate [Member] | Swap [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 10,000 |
Natural Gas [Member] | Henry Hub [Member] | Swap [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.02 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 42,050 |
Natural Gas [Member] | Henry Hub [Member] | Swap [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.29 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 21,016 |
Natural Gas [Member] | Henry Hub [Member] | Swap [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.74 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 2,870 |
Natural Gas [Member] | Henry Hub [Member] | Swap [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 0 |
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 |
Natural Gas [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 11,350 |
Derivative, Average Price Risk Option Strike Price | $ / Energy | 4 |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.66 |
Natural Gas [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 10,445 |
Derivative, Average Price Risk Option Strike Price | $ / Energy | 4 |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.69 |
Natural Gas [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 |
Derivative, Average Price Risk Option Strike Price | $ / Energy | 0 |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0 |
Natural Gas [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2019 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 |
Derivative, Average Price Risk Option Strike Price | $ / Energy | 0 |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0 |
Natural Gas [Member] | Deferred Premium [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 11,350 |
Natural Gas [Member] | Deferred Premium [Member] | Henry Hub [Member] | Put Option [Member] | Term of Calendar 2018 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | Energy / Days | 10,445 |
Financial Instruments and Fai51
Financial Instruments and Fair Value Measurements - Interest Rate Activities (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 710,000 |
Derivative, Fixed Interest Rate | 1.28% |
Term of Calendar 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 200,000 |
Derivative, Fixed Interest Rate | 1.23% |
Financial Instruments and Fai52
Financial Instruments and Fair Value Measurements - Not Designated As Hedging Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Current derivative instrument assets | $ 439,627 | $ 408,151 | ||
Other long-term assets - derivative instruments | 226,764 | 319,560 | ||
Current liabilities - derivative instruments | (4,462) | (5,457) | ||
Long-term liabilities - derivative instruments | (255) | (2,269) | ||
Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Current derivative instrument assets | 439,627 | 408,152 | ||
Other long-term assets - derivative instruments | 226,764 | 319,560 | ||
Total assets | 666,391 | 727,712 | ||
Current liabilities - derivative instruments | (4,462) | (5,458) | ||
Long-term liabilities - derivative instruments | (255) | (2,269) | ||
Total liabilities | (4,717) | (7,727) | ||
Net assets (liabilities) | 661,674 | 719,985 | ||
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Current derivative instrument assets | 397,748 | 350,351 | ||
Other long-term assets - derivative instruments | 202,140 | 296,441 | ||
Total assets | 599,888 | 646,792 | ||
Current liabilities - derivative instruments | (15) | (214) | ||
Long-term liabilities - derivative instruments | 0 | (1,520) | ||
Total liabilities | (15) | (1,734) | ||
Net assets (liabilities) | 599,873 | 645,058 | ||
Natural Gas [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Net assets (liabilities) | $ 1,848 | $ 1,672 | ||
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Current derivative instrument assets | 44,426 | 58,246 | ||
Other long-term assets - derivative instruments | 27,105 | 29,649 | ||
Total assets | 71,531 | 87,895 | ||
Current liabilities - derivative instruments | (2,740) | (563) | ||
Long-term liabilities - derivative instruments | (2,865) | (5,220) | ||
Total liabilities | (5,605) | (5,783) | ||
Net assets (liabilities) | 65,926 | 82,112 | ||
Commodity [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Net assets (liabilities) | 739,330 | |||
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Current derivative instrument assets | 222 | 0 | ||
Other long-term assets - derivative instruments | 216 | 210 | ||
Total assets | 438 | 210 | ||
Current liabilities - derivative instruments | (4,476) | (5,126) | ||
Long-term liabilities - derivative instruments | (87) | (2,269) | ||
Total liabilities | (4,563) | (7,395) | ||
Net assets (liabilities) | $ (4,125) | $ (7,185) |
Financial Instruments and Fai53
Financial Instruments and Fair Value Measurements - Gains and Losses on Derivative Instruments Not Designated As Hedging Instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 435,923 | $ 567,024 | $ (29,182) | |
Gain (loss) on commodity derivative instruments, net (note 4) | 438,614 | 566,533 | (29,182) | |
Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (loss) on commodity derivative instruments, net (note 4) | 435,923 | 567,023 | (29,182) | |
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (loss) on commodity derivative instruments, net (note 4) | [1] | 385,887 | 526,335 | (34,259) |
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (loss) on commodity derivative instruments, net (note 4) | [1] | 52,727 | 40,198 | 5,077 |
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Gain (loss) on commodity derivative instruments, net (note 4) | [2] | $ (2,691) | $ 490 | $ 0 |
[1] | Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||
[2] | Included in (gain) loss on interest rate swaps on the consolidated statements of operations |
Financial Instruments and Fai54
Financial Instruments and Fair Value Measurements - Fair Value Measurements (Details) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015USD ($)$ / Energy$ / bbl | Dec. 31, 2014USD ($)$ / Energy$ / bbl | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | $ 18,691 | $ 19,345 | |||
Fair Value, Net Asset (Liability) | 680,365 | ||||
Derivative instruments (note 4) | 439,627 | 408,151 | |||
Derivative instruments (note 4) | 226,764 | 319,560 | |||
Derivative instruments (note 4) | 4,462 | 5,457 | |||
Derivative instruments (note 4) | 255 | 2,269 | |||
Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Asset (Liability) | 18,691 | ||||
Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Asset (Liability) | 602,609 | ||||
Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Asset (Liability) | 59,065 | ||||
Natural Gas [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | $ 1,848 | $ 1,672 | |||
Natural Gas [Member] | Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 11,744 | 19,892 | 1,848 | ||
Commodity [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 739,330 | ||||
Commodity [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 19,345 | ||||
Commodity [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 638,683 | ||||
Commodity [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 81,302 | ||||
Crude Oil [Member] | Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 47,321 | 61,410 | $ 8,957 | $ 15,169 | |
Collars [Member] | Natural Gas [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 618 | 13,256 | |||
Collars [Member] | Natural Gas [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Collars [Member] | Natural Gas [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Collars [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 618 | 13,256 | |||
Collars [Member] | Crude Oil [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 29,737 | 44,405 | |||
Collars [Member] | Crude Oil [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Collars [Member] | Crude Oil [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Collars [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 29,737 | 44,405 | |||
Call Option [Member] | Natural Gas [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | ||||
Call Option [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | ||||
Put Option [Member] | Natural Gas [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 11,126 | 6,636 | |||
Put Option [Member] | Natural Gas [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Put Option [Member] | Natural Gas [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Put Option [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 11,126 | 6,636 | |||
Put Option [Member] | Crude Oil [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 17,584 | 17,005 | |||
Put Option [Member] | Crude Oil [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Put Option [Member] | Crude Oil [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Put Option [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 17,584 | 17,005 | |||
Swap [Member] | Natural Gas [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 54,182 | 62,220 | |||
Swap [Member] | Natural Gas [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Swap [Member] | Natural Gas [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 54,182 | 62,220 | |||
Swap [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Swap [Member] | Interest Rate Contract [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | (4,125) | (7,185) | |||
Swap [Member] | Interest Rate Contract [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Swap [Member] | Interest Rate Contract [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | (4,125) | (7,185) | |||
Swap [Member] | Interest Rate Contract [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Swap [Member] | Crude Oil [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 552,552 | 583,648 | |||
Swap [Member] | Crude Oil [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Swap [Member] | Crude Oil [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 552,552 | 583,648 | |||
Swap [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | |||
Option Pricing Model Valuation Technique [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Assets, Fair Value Disclosure | 81,302 | ||||
Option Pricing Model Valuation Technique [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Assets, Fair Value Disclosure | 11,744 | 19,892 | |||
Option Pricing Model Valuation Technique [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Assets, Fair Value Disclosure | 47,321 | $ 61,410 | |||
Option Pricing Model Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Assets, Fair Value Disclosure | $ 59,065 | ||||
Fair Value Inputs, Entity Credit Risk | 5.00% | 5.00% | |||
Minimum [Member] | Option Pricing Model Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Commodity Price | $ / Energy | 2.34 | 2.88 | |||
Fair Value Assumptions, Expected Volatility Rate | 23.40% | 18.59% | |||
Minimum [Member] | Option Pricing Model Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Commodity Price | $ / bbl | 37.04 | 53.27 | |||
Fair Value Assumptions, Expected Volatility Rate | 32.20% | 29.21% | |||
Maximum [Member] | Option Pricing Model Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Commodity Price | $ / Energy | 2.99 | 3.99 | |||
Fair Value Assumptions, Expected Volatility Rate | 73.10% | 63.51% | |||
Maximum [Member] | Option Pricing Model Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Crude Oil [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Commodity Price | $ / bbl | 47.79 | 71.66 | |||
Fair Value Assumptions, Expected Volatility Rate | 45.00% | 46.16% | |||
Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | $ 2,524 | $ 4,138 | |||
Equity Securities [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 2,524 | 4,138 | |||
Equity Securities [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | ||||
Equity Securities [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | ||||
Equity Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 11,190 | 10,577 | |||
Equity Funds [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 11,190 | 10,577 | |||
Equity Funds [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | ||||
Equity Funds [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | 0 | |||
Exchange Traded Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 4,977 | 4,630 | |||
Exchange Traded Funds [Member] | Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 4,977 | 4,630 | |||
Exchange Traded Funds [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | 0 | |||
Exchange Traded Funds [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value | 0 | 0 | |||
Not Designated as Hedging Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 661,674 | 719,985 | |||
Derivative instruments (note 4) | 439,627 | 408,152 | |||
Derivative instruments (note 4) | 226,764 | 319,560 | |||
Derivative Asset | 666,391 | 727,712 | |||
Derivative instruments (note 4) | 4,462 | 5,458 | |||
Derivative instruments (note 4) | 255 | 2,269 | |||
Derivative Liability | 4,717 | 7,727 | |||
Not Designated as Hedging Instrument [Member] | Commodity derivative Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | [1] | 0 | |||
Derivative instruments (note 4) | [1] | (2,769) | (445) | ||
Derivative instruments (note 4) | [1] | (2,697) | (6,740) | ||
Derivative Asset | [1] | (5,466) | (7,185) | ||
Derivative instruments (note 4) | [1] | (2,769) | (445) | ||
Derivative instruments (note 4) | [1] | (2,697) | (6,740) | ||
Derivative Liability | [1] | (5,466) | (7,185) | ||
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 65,926 | 82,112 | |||
Derivative instruments (note 4) | 44,426 | 58,246 | |||
Derivative instruments (note 4) | 27,105 | 29,649 | |||
Derivative Asset | 71,531 | 87,895 | |||
Derivative instruments (note 4) | 2,740 | 563 | |||
Derivative instruments (note 4) | 2,865 | 5,220 | |||
Derivative Liability | 5,605 | 5,783 | |||
Not Designated as Hedging Instrument [Member] | Crude Oil [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | 599,873 | 645,058 | |||
Derivative instruments (note 4) | 397,748 | 350,351 | |||
Derivative instruments (note 4) | 202,140 | 296,441 | |||
Derivative Asset | 599,888 | 646,792 | |||
Derivative instruments (note 4) | 15 | 214 | |||
Derivative instruments (note 4) | 0 | 1,520 | |||
Derivative Liability | 15 | 1,734 | |||
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets (Liabilities), at Fair Value, Net | (4,125) | (7,185) | |||
Derivative instruments (note 4) | 222 | 0 | |||
Derivative instruments (note 4) | 216 | 210 | |||
Derivative Asset | 438 | 210 | |||
Derivative instruments (note 4) | 4,476 | 5,126 | |||
Derivative instruments (note 4) | 87 | 2,269 | |||
Derivative Liability | $ 4,563 | $ 7,395 | |||
[1] | Represents counterparty netting under derivative netting agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These contracts are reflected net on the consolidated balance sheet. |
Financial Instruments and Fai55
Financial Instruments and Fair Value Measurements - Reconciation of Changes in Fair Value (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Realized gain (loss) | $ (435,923) | $ (567,024) | $ 29,182 | |||
Crude Oil [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Derivative instruments, purchases | [1],[2] | 11,170 | 0 | |||
Crude Oil [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Beginning balance | 61,410 | 8,957 | 15,169 | |||
Realized gain (loss) | [2] | 44,647 | 4,094 | (125) | ||
Derivative instruments, purchases | [1],[2] | 0 | ||||
Unrealized loss | [3],[4] | (58,736) | 37,189 | (6,087) | ||
Ending balance | 47,321 | 61,410 | 8,957 | |||
Natural Gas [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Beginning balance | 1,848 | 1,672 | ||||
Ending balance | 1,848 | |||||
Natural Gas [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Beginning balance | 19,892 | 1,848 | ||||
Realized gain (loss) | [2] | 16,815 | 815 | (892) | ||
Derivative instruments, purchases | 0 | [1],[2] | 11,872 | 0 | [1],[2] | |
Unrealized loss | [3],[4] | (24,963) | 5,357 | 1,068 | ||
Ending balance | $ 11,744 | $ 19,892 | $ 1,848 | |||
[1] | 2014 purchases related to derivative instruments novated to us in connection with the QRE Merger. | |||||
[2] | Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||
[3] | Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||
[4] | Represents gain (loss) on mark-to-market of derivative instruments. |
Financial Instruments and Fai56
Financial Instruments and Fair Value Measurements Prepaid Premiums (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Commodity Contract [Member] | |||
Prepaid Derivative Premiums [Line Items] | |||
Prepaid Derivative Premium | $ 6,700 | $ 8,500 | $ 4,900 |
Option Pricing Model Valuation Technique [Member] | Level 3 [Member] | |||
Prepaid Derivative Premiums [Line Items] | |||
Assets, Fair Value Disclosure | 81,302 | ||
Option Pricing Model Valuation Technique [Member] | Level 3 [Member] | Crude Oil [Member] | |||
Prepaid Derivative Premiums [Line Items] | |||
Assets, Fair Value Disclosure | 47,321 | 61,410 | |
Option Pricing Model Valuation Technique [Member] | Level 3 [Member] | Natural Gas [Member] | |||
Prepaid Derivative Premiums [Line Items] | |||
Assets, Fair Value Disclosure | 11,744 | $ 19,892 | |
Derivative Financial Instruments, Assets [Member] | Option Pricing Model Valuation Technique [Member] | Level 3 [Member] | |||
Prepaid Derivative Premiums [Line Items] | |||
Assets, Fair Value Disclosure | $ 59,065 | ||
Fair Value Inputs, Entity Credit Risk | 5.00% | 5.00% |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Impairments of oil and natural gas properties (note 6) | $ 2,377,615,000 | $ 149,000,000 | $ 54,373,000 |
Oil and gas sales | 645,272,000 | 855,820,000 | 660,665,000 |
PCEC [Member] | |||
Related Party Transaction [Line Items] | |||
Monthly fees associated with the Administrative Service Agreement | 700,000 | ||
Payroll and administrative expense | 9,600,000 | 10,900,000 | 10,600,000 |
Current receivables | 1,700,000 | 2,400,000 | |
Indirect expenses | 8,400,000 | 8,400,000 | $ 8,400,000 |
FLORIDA | |||
Related Party Transaction [Line Items] | |||
Impairments of oil and natural gas properties (note 6) | 443,800,000 | $ 124,800,000 | |
Senior Secured Notes [Member] | EIG [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | 13,000,000 | ||
Series B [Member] | EIG [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | $ 7,000,000 |
Impairments (Details)
Impairments (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jul. 15, 2013 | |
Reserve Quantities [Line Items] | |||||
Percentage Rate Of Escalation, Impairment Of Assets | 2.00% | ||||
Discount Rate, Future Net Revenues for Estimated Proved Reserves | 10.00% | ||||
Impairments of oil and natural gas properties (note 6) | $ 2,377,615 | $ 149,000 | $ 54,373 | ||
Impairments of oil and natural gas properties | 2,377,615 | 149,000 | 54,373 | ||
Impairment of goodwill (note 6) | $ 95,900 | 95,947 | 0 | 0 | |
FLORIDA | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 443,800 | 124,800 | |||
Ark-La-Tex [Member] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 512,800 | ||||
Rockies [Domain] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 147,900 | 11,200 | |||
Michigan Kentucky Indiana [Domain] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 740,600 | 8,500 | |||
Permian Basin [Domain] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 256,500 | 2,300 | |||
Mid-Cont [Member] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | $ 2,200 | ||||
California [Member] [Member] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 213,000 | ||||
MidContinent [Domain] | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | $ 63,000 | ||||
WYOMING | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | 25,300 | ||||
MICHIGAN | |||||
Reserve Quantities [Line Items] | |||||
Impairments of oil and natural gas properties (note 6) | $ 28,300 | ||||
Oklahoma Panhandle [Member] | |||||
Reserve Quantities [Line Items] | |||||
Derivative assets - current | $ 14,739 |
Investments (Details)
Investments (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Available-for-sale Securities [Line Items] | ||
Cost Basis | $ 19,588 | $ 19,634 |
Unrealized Gains | 3,372 | 139 |
Unrealized Losses | (4,269) | (428) |
Fair Value | 18,691 | 19,345 |
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds | 3,900 | 500 |
Available-for-sale Securities, Gross Realized Losses | 100 | 100 |
Equity Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost Basis | 2,591 | 4,203 |
Unrealized Gains | 141 | 92 |
Unrealized Losses | (208) | (157) |
Fair Value | 2,524 | 4,138 |
Equity Funds [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost Basis | 13,276 | 10,623 |
Unrealized Gains | 1,737 | 20 |
Unrealized Losses | (3,823) | (66) |
Fair Value | 11,190 | 10,577 |
Exchange Traded Funds [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost Basis | 3,721 | 4,808 |
Unrealized Gains | 1,494 | 27 |
Unrealized Losses | (238) | (205) |
Fair Value | $ 4,977 | $ 4,630 |
Other Assets Intangible Assets
Other Assets Intangible Assets (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($)contract | Jul. 15, 2013USD ($) | |
Finite-Lived Intangible Assets | ||||
Unamortized Debt Issuance Expense | $ 59,167 | $ 52,787 | ||
Fair Value | 18,691 | 19,345 | ||
Deposits Assets, Noncurrent | 0 | 50,792 | ||
Intangible Assets, Current | 365 | 8,336 | ||
Other Assets, Miscellaneous, Noncurrent | 10,650 | 5,120 | ||
Other long-term assets (note 8) | 117,872 | $ 165,378 | ||
CO2 Purchase Contract | 2 | |||
TransferIntangibletoPPE | (5,100) | |||
Whiting [Domain] | ||||
Finite-Lived Intangible Assets | ||||
CO2 Purchase Contract | contract | 2 | |||
CO2 Purchase Contracts | $ 14,700 | $ 14,700 | ||
Amortization of Intangible Assets | 2,200 | $ 3,900 | $ 3,600 | |
Net Profit Interest Obligation [Member] | ||||
Finite-Lived Intangible Assets | ||||
Deposits Assets, Noncurrent | 18,263 | 18,263 | ||
Property Reclamation Deposit [Member] | ||||
Finite-Lived Intangible Assets | ||||
Deposits Assets, Noncurrent | $ 10,736 | $ 10,735 |
Other Assets Other Long-Term As
Other Assets Other Long-Term Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Other Assets Disclosure [Abstract] | ||
Other long-term assets (note 8) | $ 117,872 | $ 165,378 |
Other Long-Term Assets [Line Items] | ||
Deposits Assets, Noncurrent | 0 | 50,792 |
Letters of Credit Outstanding, Amount | 25,800 | 26,500 |
Net Profit Interest Obligation [Member] | ||
Other Long-Term Assets [Line Items] | ||
Share of excess historical production costs | 9,800 | 2,300 |
Deposits Assets, Noncurrent | 18,263 | 18,263 |
Property Reclamation Deposit [Member] | ||
Other Long-Term Assets [Line Items] | ||
Deposits Assets, Noncurrent | 10,736 | 10,735 |
Letters of Credit Outstanding, Amount | $ 23,400 | $ 23,400 |
Long-Term Debt - Senior Notes (
Long-Term Debt - Senior Notes (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2015 | Apr. 08, 2015 | Dec. 31, 2014 | Jan. 10, 2012 | Oct. 06, 2010 | |
Debt Instrument [Line Items] | |||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,800,000,000 | $ 2,500,000,000 | |||
Notes Payable | 2,938,000 | 1,100,000 | |||
Commitment from existing lenders, borrowing base | 1,800,000,000 | ||||
Senior notes at fair value | 650,000,000 | 0 | |||
Unamortized Debt Issuance Expense | 59,167,000 | 52,787,000 | |||
Credit facility debt | 1,229,000,000 | 2,194,500,000 | |||
Debt Instrument, Unamortized Discount (Premium), Net | 15,781,000 | (1,560,000) | |||
Senior Secured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Proceeds from (Payments for) Other Financing Activities | 606,900,000 | ||||
Interest rate, stated percentage | 9.25% | ||||
Debt Instrument, Discount or Premium Percentage | 97.00% | ||||
Senior notes at fair value | $ 650,000,000 | ||||
Subordinated Long-term Debt, Noncurrent | 632,700,000 | ||||
Debt Instrument, Unamortized Discount | 17,300,000 | ||||
Fair value of debt instrument | 518,000,000 | ||||
Unamortized Debt Issuance Expense | 20,600,000 | ||||
Senior Notes due 2020 | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, face amount | 305,000,000 | 305,000,000 | |||
Interest rate, stated percentage | 8.625% | ||||
Deferred finance costs, net | $ 8,800,000 | ||||
Notes issued, discount | 98.358% | ||||
Subordinated Long-term Debt, Noncurrent | 302,100,000 | 302,100,000 | $ 300,000,000 | ||
Debt Instrument, Unamortized Discount | 2,900,000 | 2,900,000 | $ 5,000,000 | ||
Fair value of debt instrument | 59,000,000 | 262,000,000 | |||
Unamortized Debt Issuance Expense | 4,200,000 | 5,100,000 | |||
Senior Notes due 2022 | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, face amount | 850,000,000 | 850,000,000 | |||
Interest rate, stated percentage | 7.875% | ||||
Subordinated Long-term Debt, Noncurrent | 854,500,000 | 854,500,000 | |||
Debt Instrument, Unamortized Discount | 4,500,000 | 4,500,000 | |||
Fair value of debt instrument | 157,000,000 | 661,000,000 | |||
Unamortized Debt Issuance Expense | $ 12,200,000 | $ 14,100,000 |
Long-Term Debt - Credit Facilit
Long-Term Debt - Credit Facility (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Debt Instrument [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 5,000,000 | |
Line of credit facility, current borrowing base | 1,800,000 | $ 2,500,000 |
Credit facility debt | 1,229,000 | 2,194,500 |
Write off of Deferred Debt Issuance Cost | 10,600 | |
Credit facility (note 9) | $ 1,075,000 | 2,089,500 |
Debt Instrument, Percentage of Borrowing Base not Exceeded, Terminated Derivative Contracts | 5.00% | |
Commitment from existing lenders, borrowing base | $ 1,800,000 | |
Long-term Debt, Current Maturities | $ 154,000 | 105,000 |
Interest Coverage Ratio | 2.5 | |
Current ratio | 1 | |
Unamortized Debt Issuance Expense | $ 59,167 | 52,787 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized Debt Issuance Expense | 22,100 | $ 33,500 |
London Interbank Offered Rate (LIBOR) [Member] | ||
Debt Instrument [Line Items] | ||
Credit facility debt | $ 1,230,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.6084% | |
Well Fargo Bank National Association [Member] | ||
Debt Instrument [Line Items] | ||
Percentage of total value of borrowing secured by oil and gas properties | 80.00% |
Long-Term Debt - Interest Expen
Long-Term Debt - Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Debt Instrument [Line Items] | ||||
Amortization of Financing Costs and Discounts | $ 24,926 | [1] | $ 7,836 | $ 6,429 |
Interest costs, capitalized during period | (155) | (326) | (128) | |
Interest Costs Incurred | 203,027 | 126,960 | 87,067 | |
Interest Paid | 181,873 | 119,488 | 74,078 | |
Write off of Deferred Debt Issuance Cost | 10,600 | |||
Senior Secured Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest Expense, Debt, Excluding Amortization | 43,758 | 0 | 0 | |
Unsecured Debt [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest Expense, Debt, Excluding Amortization | 93,244 | 95,662 | 65,068 | |
Line of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest Expense, Debt, Excluding Amortization | $ 41,254 | $ 23,788 | $ 15,698 | |
[1] | (a) The year ended December 31, 2015 included a write-off of $10.6 million of debt issuance costs related to the reduction of our credit facility borrowing base. |
Long-Term Debt Long-Term Debt T
Long-Term Debt Long-Term Debt Table (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Jan. 10, 2012 | Oct. 06, 2010 |
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,800,000 | $ 2,500,000 | ||
Credit facility debt | 1,229,000 | 2,194,500 | ||
Notes Payable | 2,938 | 1,100 | ||
Senior notes at fair value | 650,000 | 0 | ||
Debt Instrument, Unamortized Discount (Premium), Net | (15,781) | 1,560 | ||
Debt, Long-term and Short-term, Combined Amount | 3,021,157 | 3,352,160 | ||
Long-term Debt, Current Maturities | (154,000) | (105,000) | ||
Long-term Debt | 2,867,157 | 3,247,160 | ||
Commitment from existing lenders, borrowing base | 1,800,000 | |||
Notes Payable to Bank | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Current Borrowing Capacity | $ 6,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 2.3584% | |||
Senior Notes due 2020 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 8.625% | |||
Debt Instrument, Face Amount | $ 305,000 | 305,000 | ||
Debt Instrument, Unamortized Discount | 2,900 | 2,900 | $ 5,000 | |
Senior Notes due 2022 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | |||
Debt Instrument, Face Amount | 850,000 | 850,000 | ||
Debt Instrument, Unamortized Discount | $ 4,500 | $ 4,500 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Operating Loss Carryforwards | $ 10,900 | |||
Current | 626 | $ 212 | $ 472 | |
Deferred | [1] | 784 | (173) | 262 |
State income tax expense (benefit) | [2] | 117 | (112) | 171 |
Income (loss) subject to federal income tax | (2,581,486) | 421,243 | (42,766) | |
Income tax expense (benefit) | 1,527 | (73) | 905 | |
Deferred tax assets, Asset retirement obligations | 2,296 | 2,120 | ||
Deferred Tax Assets, Operating Loss Carryforwards, Domestic | 3,714 | 2,341 | ||
Deferred tax assets, Unrealized hedge loss | 823 | 952 | ||
Tax Credit Carryforward, Deferred Tax Asset | 0 | 440 | ||
Deferred tax assets, Other | 309 | 103 | ||
Deferred Tax Assets, Valuation Allowance | (6,542) | (4,243) | ||
Deferred tax liabilities, Depreciation, depletion and intangible drilling costs | (6,505) | (6,455) | ||
Net deferred tax liability | (3,448) | (2,035) | ||
Deferred income taxes (note 11) | 3,844 | 2,575 | ||
Deferred Tax Assets, Gross, Noncurrent | 400 | 600 | ||
Cash paid for federal and state income taxes | 500 | 200 | $ 500 | |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Compensation | 1,558 | 1,315 | ||
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Pensions | 1,724 | 2,461 | ||
Deferred Tax Liabilities, Unrealized Hedge Gains | 825 | $ 1,069 | ||
QR Energy LP [Member] | ||||
Operating Loss Carryforwards | 5,900 | |||
Annual NOL Carryforward Limitation | $ 600 | |||
[1] | Related to Phoenix and Breitburn Management, our wholly-owned subsidiaries, and ETSWDC, a subsidiary we have a controlling interest in. | |||
[2] | Primarily in California and Texas. |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations [Line Items] | ||||
Asset Retirement Obligation, Current | $ (2,341) | $ (4,948) | ||
Credit adjusted risk free rate | 14.00% | 7.00% | ||
Inflation adjustment rate | 2.00% | 2.00% | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Carrying amount, beginning of period | $ 238,411 | $ 123,769 | ||
Acquisitions | 796 | 95,800 | ||
Liabilities incurred | 2,268 | 4,020 | ||
Liabilities settled | (7,744) | (1,708) | ||
Asset Retirement Obligation, Divested properties | (261) | 0 | ||
Revisions | 3,954 | 6,770 | ||
Accretion expense | 16,954 | 9,760 | ||
Carrying amount, end of period | $ 238,411 | $ 123,769 | 254,378 | 238,411 |
Asset retirement obligation (note 12) | $ 252,037 | $ 233,463 | ||
Minimum [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Finite-Lived Intangible Asset, Useful Life | 1 year | |||
Maximum [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Finite-Lived Intangible Asset, Useful Life | 50 years |
Pension and Postretirement Be68
Pension and Postretirement Benefits Pension and Postretirement Benefits (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate | $ 100 | ||
Defined Benefit Plan, Impact of 1% Increase in Assumption Used to Calculate Benefit Obligation | 500 | ||
Defined Benefit Plan, Impact of 1% Decrease in Assumption Used to Calculate Benefit Obligation | 400 | ||
Pension Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Employer Discretionary Contribution Amount | 0 | ||
Liability loss due to assumption change | (2,045) | $ 474 | |
Long-term liabilities | $ 5,298 | $ 6,610 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.10% | 3.75% | |
Defined Benefit Plan, Assumptions used to calculate benefit costs, discount rate | 3.75% | 3.90% | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $ 1,500 | ||
Projected benefit obligation | 25,320 | $ 27,829 | $ 0 |
Accumulated benefit obligation | 24,424 | 26,872 | |
Fair value of plan assets | 20,022 | $ 21,219 | 0 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 1,510 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 1,540 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 1,580 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 1,650 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | $ 8,620 | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.00% | 3.00% | |
Defined benefit plan assumption, expected long-term rate of return | 6.75% | 6.50% | |
2014 Acquisition of ETSWDC | $ 0 | $ 27,300 | |
Service cost | 271 | 33 | |
Interest cost | 1,014 | 120 | |
Plan participant contributions | 0 | 0 | |
Actuarial loss | (2,360) | 496 | |
Benefits paid | (1,434) | (120) | |
2014 Acquisition of ETSWDC | 0 | 21,319 | |
Actual return on plan assets | (163) | 20 | |
Employer contributions | 400 | 0 | |
Under funded status at end of year | (5,298) | (6,610) | |
Expected return on plan assets | (1,342) | (152) | |
Net periodic benefit costs | (57) | 1 | |
Liability loss (gain) due to participant experience | (315) | 22 | |
Asset return loss | 1,505 | 132 | |
Net actuarial loss | (855) | 628 | |
Total | $ (855) | $ 628 | |
Expected long-term return on plan assets | 6.50% | 6.50% | |
Rate of compensation increase | 3.00% | 3.00% | |
Other Postretirement Benefit Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 200 | ||
Liability loss due to assumption change | (220) | $ 88 | |
Long-term liabilities | $ 2,503 | $ 2,713 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.10% | 3.75% | |
Defined Benefit Plan, Assumptions used to calculate benefit costs, discount rate | 3.75% | 3.75% | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate | 0.0700 | 0.0600 | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $ 150 | ||
Projected benefit obligation | 3,971 | $ 4,240 | 0 |
Accumulated benefit obligation | 3,971 | 4,240 | |
Fair value of plan assets | 1,468 | $ 1,527 | $ 0 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 170 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 190 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 210 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 230 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | $ 1,060 | ||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year, Before Age 65 | 0.0700 | 0.0700 | |
Defined benefit plan assumption, expected long-term rate of return | 6.75% | 6.50% | |
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 4.50% | 4.50% | |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2,023 | 2,022 | |
2014 Acquisition of ETSWDC | $ 0 | $ 4,144 | |
Service cost | 34 | 4 | |
Interest cost | 155 | 18 | |
Plan participant contributions | (28) | (2) | |
Actuarial loss | (333) | 85 | |
Benefits paid | (153) | (13) | |
2014 Acquisition of ETSWDC | 0 | 1,518 | |
Actual return on plan assets | (63) | 9 | |
Employer contributions | 129 | 11 | |
Under funded status at end of year | (2,503) | (2,713) | |
Expected return on plan assets | (99) | (11) | |
Net periodic benefit costs | 90 | 11 | |
Liability loss (gain) due to participant experience | (113) | (3) | |
Asset return loss | 162 | 3 | |
Net actuarial loss | (171) | 88 | |
Total | $ (171) | $ 88 | |
Expected long-term return on plan assets | 6.50% | 6.50% | |
Cash [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | $ 100 | $ 100 | |
Mutual Funds [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 1,400 | 1,400 | |
Fixed Income Funds [Member] | Pension Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | 12,000 | 11,600 | |
Equity [Member] | Pension Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets | $ 8,000 | $ 9,600 |
Commitments and Contingencies69
Commitments and Contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Long-term Purchase Commitment [Line Items] | |||
Lease and rental expense | $ 8,900 | $ 5,200 | $ 3,900 |
Surety bonds, current carrying value | 27,100 | 21,100 | |
Letters of Credit Outstanding, Amount | 25,800 | 26,500 | |
Operating leases, 2016 | 11,368 | ||
Operating leases, 2017 | 11,323 | ||
Operating leases, 2018 | 7,037 | ||
Operating leases, 2019 | 5,615 | ||
Operating leases, 2020 | 5,648 | ||
Operating leases, Thereafter | 14,480 | ||
Operating leases, Total | 55,471 | ||
Property Reclamation Deposit [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Letters of Credit Outstanding, Amount | $ 23,400 | $ 23,400 |
Partners' Equity (Details)
Partners' Equity (Details) $ / shares in Units, CommonUnit in Thousands, $ in Thousands | Jun. 15, 2015shares | May. 15, 2015shares | May. 21, 2014USD ($)$ / sharesshares | Nov. 30, 2014USD ($)$ / unitsshares | Oct. 31, 2014USD ($)$ / unitsshares | Mar. 31, 2014USD ($) | Nov. 30, 2013USD ($)$ / unitsshares | Feb. 28, 2013USD ($)$ / unitsshares | Dec. 31, 2015USD ($)CommonUnit$ / sharesshares | Dec. 31, 2014USD ($)CommonUnit$ / sharesshares | Dec. 31, 2013USD ($)units$ / sharesshares | Apr. 08, 2015USD ($)$ / shares | Dec. 31, 2012shares |
Capital Unit [Line Items] | |||||||||||||
Series B perpetual convertible preferred units, 48.8 million and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively (note 15) | $ 353,471 | $ 0 | |||||||||||
Partners' Capital Account, Private Placement of Units | 337,238 | ||||||||||||
Stock Issued During Period, Shares, Non Cash Stock Dividend | shares | 0.006666 | 0.008222 | |||||||||||
Less: Non-cash distributions to Series B preferred unitholders | 20,817 | 0 | $ 0 | ||||||||||
Proceeds from issuance of common units, net | $ 251,600 | $ 285,000 | 3,008 | 277,613 | 618,013 | ||||||||
Preferred Units, Issued | shares | 8,000,000 | ||||||||||||
Distributions to preferred unitholders | 16,502 | $ 9,350 | $ 0 | ||||||||||
Preferred Stock, Redemption Price Per Share | $ / shares | $ 25 | ||||||||||||
Partners' Capital, 2nd Monthly Installment Distribution | 45 days | ||||||||||||
Partners' Capital, distribution period | 75 days | ||||||||||||
Distribution Made to Limited Partner, Cash Distributions Declared | $ (123,217) | $ (260,958) | $ 183,594 | ||||||||||
Partners' Capital, 1st Monthly Distribution | 17 days | ||||||||||||
Common units | shares | 213,500,000 | 210,900,000 | |||||||||||
Long-term incentive compensation plans, number of shares authorized | shares | 24,700,000 | 9,700,000 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number | shares | 14,100,000 | 3,300,000 | |||||||||||
Partners' Capital Account, Units, Sold in Public Offering | shares | 14,000,000 | 18,980,000 | 14,950,000 | 0 | |||||||||
Price Per Common Unit | $ / units | 14.73 | 18.64 | 18.22 | 19.86 | |||||||||
Partners' Capital Account, Public Sale of Units | $ 333,200 | $ 3,115 | $ 277,605 | $ 617,752 | |||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 261,000 | $ 183,600 | |||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares | $ 0.58 | $ 2 | $ 1.91 | ||||||||||
Distributions Paid On Unissued Units Under Incentive Plans | $ (2,971) | $ (3,626) | $ 3,274 | ||||||||||
Equity interest issued or issuable, value assigned | $ 1,060,000 | ||||||||||||
Preferred Stock, Dividend Rate, Percentage | 8.25% | ||||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 25 | ||||||||||||
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at December 31, 2015 and December 31, 2014 (note 15) | $ 193,200 | $ 193,215 | 193,215 | ||||||||||
Preferred Units, Offering Costs | $ 6,800 | ||||||||||||
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ / shares | $ 0.171875 | ||||||||||||
Less: Distributions to Series A preferred unitholders | $ 16,500 | $ 10,083 | 0 | ||||||||||
Maximum Proceeds - Issuance of Common Units Under Equity Distribution Agreement | $ 200,000 | ||||||||||||
Common Units [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Common Units issued pursuant to vest grants | shares | 600,000 | ||||||||||||
Antares [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Price Per Common Unit | $ / units | 16.91 | ||||||||||||
Common units issued during acquisition | shares | 4,300,000 | ||||||||||||
Equity interest issued or issuable, value assigned | $ 72,700 | ||||||||||||
QR Energy LP [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Common units issued during acquisition | shares | 71,500,000 | ||||||||||||
Equivalent Units [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Dividends, Share-based Compensation, Cash | $ 3,800 | 3,300 | |||||||||||
Preferred Units B [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Series B perpetual convertible preferred units, 48.8 million and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively (note 15) | $ 350,000 | ||||||||||||
Partners' Capital Account, Private Placement of Units | 337,238 | ||||||||||||
Distribution Made to Limited Partner, Cash Distributions Declared | $ 0 | $ 0 | $ 0 | ||||||||||
Common units | shares | 48,831,000 | 0 | 0 | 0 | |||||||||
Common Units issued under incentive plans (shares) | 0 | 0 | 0 | ||||||||||
Partners' Capital Account, Units, Sold in Public Offering | shares | 0 | 0 | |||||||||||
Partners' Capital Account, Public Sale of Units | $ 0 | $ 0 | $ 0 | ||||||||||
Distributions Paid On Unissued Units Under Incentive Plans | 0 | 0 | $ 0 | ||||||||||
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 7.50 | ||||||||||||
Equity Distribution Agreement [Member] | |||||||||||||
Capital Unit [Line Items] | |||||||||||||
Proceeds from issuance of common units, net | $ 3,100 | $ 26,200 | |||||||||||
Stock Issued During Period, Shares, New Issues | shares | 500,000 | 1,300,000 |
Partners' Equity - Earnings Per
Partners' Equity - Earnings Per Share Reconciliation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Partners' Capital [Abstract] | ||||
Net income (loss) | $ (2,583,339) | $ 421,333 | $ (43,671) | |
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic | 0 | 5,348 | 0 | |
Distributions on participating units not expected to vest | 16,500 | 10,083 | 0 | |
Less: Non-cash distributions to Series B preferred unitholders | 20,817 | 0 | 0 | |
Net Income (Loss) Available to Common Stockholders, Basic | (2,622,387) | 405,902 | (43,671) | |
Less: Distributions on participating units in excess of earnings | $ 1,731 | $ 0 | $ 0 | |
Weighted average number of units used to calculate basic and diluted income loss per unit [Abstract] | ||||
Weighted Partners' Capital Account, Units | 211,575 | 133,451 | 101,604 | |
Weighted Average Number of Shares Outstanding, Diluted | 211,575 | 134,206 | 101,604 | |
Dilutive units | 0 | 755 | 0 | |
Net income (loss) per common unit [Abstract] | ||||
Basic | $ (12.3945976604) | $ 3.04 | $ (0.43) | |
Diluted | (12.3945976604) | $ 3.02 | $ (0.43) | |
Capital Unit [Line Items] | ||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 261,000 | $ 183,600 | ||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.58 | $ 2 | $ 1.91 | |
Weighted average anti-dilutive units excluded from the calculation | [1] | 1 | 364 | |
Equivalent Units [Member] | ||||
Capital Unit [Line Items] | ||||
Dividends, Share-based Compensation, Cash | $ 3,800 | $ 3,300 | ||
[1] | The years ended December 31, 2015 and December 31, 2013 exclude 725 and 364 weighted average anti-dilutive units, respectively, from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. |
Accumulated Other Comprehensi72
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Less: Accumulated comprehensive loss attributable to non-controlling interest | $ (112) | $ (270) | |
Accumulated comprehensive loss attributable to the Partnership | (229) | (392) | |
Accumulated Other Comprehensive Income [Roll Forward] | |||
Accumulated other comprehensive income (loss), beginning balance | (662) | 0 | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | 410 | ||
Amounts reclassified from accumulated other comprehensive loss | 135 | (662) | |
Other Comprehensive (Income) Loss, Net of Tax, Including Portion Attributable to Noncontrolling Interest | 275 | (662) | $ 0 |
Accumulated other comprehensive income (loss), ending balance | (117) | (662) | $ 0 |
Available-For-Sale Securities | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Less: Accumulated comprehensive loss attributable to non-controlling interest | 164 | (77) | |
Accumulated comprehensive loss attributable to the Partnership | (350) | (112) | |
Accumulated Other Comprehensive Income [Roll Forward] | |||
Accumulated other comprehensive income (loss), beginning balance | (189) | ||
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (267) | ||
Amounts reclassified from accumulated other comprehensive loss | (135) | (189) | |
Other Comprehensive (Income) Loss, Net of Tax, Including Portion Attributable to Noncontrolling Interest | (402) | (189) | |
Accumulated other comprehensive income (loss), ending balance | (514) | (189) | |
Pension and Postretirement Benefits | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Less: Accumulated comprehensive loss attributable to non-controlling interest | (276) | (193) | |
Accumulated comprehensive loss attributable to the Partnership | 121 | (280) | |
Accumulated Other Comprehensive Income [Roll Forward] | |||
Accumulated other comprehensive income (loss), beginning balance | (473) | ||
Other Comprehensive Income (Loss), before Reclassifications, before Tax | 677 | ||
Amounts reclassified from accumulated other comprehensive loss | 0 | (473) | |
Other Comprehensive (Income) Loss, Net of Tax, Including Portion Attributable to Noncontrolling Interest | 677 | (473) | |
Accumulated other comprehensive income (loss), ending balance | $ 397 | $ (473) |
Noncontrolling Interest (Detail
Noncontrolling Interest (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Noncontrolling Interest [Abstract] | ||
Ownership percentage by noncontrolling owners | 59.00% | |
Noncontrolling interest (note 17) | $ 7,324 | $ 6,885 |
Unit Based Compensation Plans -
Unit Based Compensation Plans - Narrative (Details) shares in Millions | 1 Months Ended | 12 Months Ended | |||||
Nov. 30, 2014$ / units | Oct. 31, 2014$ / units | Nov. 30, 2013$ / units | Feb. 28, 2013$ / units | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)$ / units | Dec. 31, 2013USD ($)$ / unitsshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | $ 26,805,000 | $ 23,387,000 | $ 19,955,000 | ||||
Price Per Common Unit | $ / units | 14.73 | 18.64 | 18.22 | 19.86 | |||
Unit Based Compensation [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | 26,805,000 | 23,400,000 | 20,000,000 | ||||
Allocated Share-based Compensation Expense | $ 20,217,000 | 18,300,000 | 17,000,000 | ||||
Award vesting period | 3 years | ||||||
Unrecognized compensation cost | $ 23,298,000 | ||||||
Fair value of vested units | 19,734,000 | 18,400,000 | $ 17,200,000 | ||||
2013 Convertible Phantom Units (CPUs) [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted, Number | shares | 0.3 | ||||||
Convertible Phantom Units (CPUs) [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | $ 4,300,000 | $ 2,300,000 | |||||
Price Per Common Unit | $ / units | 20.29 | 20.98 | |||||
Director Restricted Phantom Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | $ 900,000 | $ 800,000 | $ 700,000 | ||||
Award vesting period | 2 years | ||||||
Unrecognized compensation cost | $ 1,000,000 | ||||||
General and Administrative Expense [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | 25,462,000 | ||||||
Restructuring Charges [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unit-based compensation expense | $ 1,343,000 |
Unit Based Compensation Plans-
Unit Based Compensation Plans- Restricted Phantom Units (Details) | 1 Months Ended | 12 Months Ended | ||||||
Nov. 30, 2014$ / units | Oct. 31, 2014$ / units | Nov. 30, 2013$ / units | Feb. 28, 2013$ / units | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)$ / shares$ / unitsshares | Dec. 31, 2013USD ($)$ / shares$ / unitsshares | ||
RPUs Weighted Average Grant Date [Roll Forward] | ||||||||
Shares Paid for Tax Withholding for Share Based Compensation | 613,000 | 298 | 308 | |||||
Price Per Common Unit | $ / units | 14.73 | 18.64 | 18.22 | 19.86 | ||||
Unit-based compensation expense | $ | $ 26,805,000 | $ 23,387,000 | $ 19,955,000 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number | 100,000 | |||||||
Convertible Phantom Units (CPUs) [Member] | ||||||||
RPUs Weighted Average Grant Date [Roll Forward] | ||||||||
Price Per Common Unit | $ / units | 20.29 | 20.98 | ||||||
Unit-based compensation expense | $ | $ 4,300,000 | $ 2,300,000 | ||||||
Unit Based Compensation [Member] | ||||||||
RPUs Weighted Average Grant Date [Roll Forward] | ||||||||
Award vesting period | 3 years | |||||||
Allocated Share-based Compensation Expense | $ | $ 20,217,000 | 18,300,000 | 17,000,000 | |||||
Fair value of vested units | $ | 19,734,000 | 18,400,000 | 17,200,000 | |||||
Unit-based compensation expense | $ | 26,805,000 | $ 23,400,000 | $ 20,000,000 | |||||
Unrecognized compensation cost | $ | $ 23,298,000 | |||||||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years | |||||||
Restricted Phantom Units (RPUs) [Member] | ||||||||
Number of RPUs [Roll Forward] | ||||||||
Outstanding, beginning of period, Number | 957,000 | 896,000 | 817,000 | |||||
Granted, Number | 4,739,000 | 1,025,000 | 919,000 | |||||
Exercised, Number | [1] | (2,012,000) | (906,000) | (833,000) | ||||
Cancelled, Number | (646,000) | (58,000) | (7,000) | |||||
Outstanding, end of period, Number | 3,038,000 | 957,000 | 896,000 | |||||
RPUs Weighted Average Grant Date [Roll Forward] | ||||||||
Outstanding, beginning of period, Weighted Average Fair Value | $ / shares | $ 20.98 | $ 21.05 | $ 20.92 | |||||
Granted, Weighted Average Fair Value | $ / shares | 6.46 | 20.21 | 20.77 | |||||
Exercised, Weighted Average Fair Value | $ / shares | [1] | 10.63 | 20.22 | 20.62 | ||||
Cancelled, Weighted Average Fair Value | $ / shares | 8.24 | 20.36 | 21.60 | |||||
Outstanding, end of period, Weighted Average Fair Value | $ / shares | $ 7.90 | $ 20.98 | $ 21.05 | |||||
2014 Convertible Phantom Units (CPUs) [Member] | ||||||||
Number of RPUs [Roll Forward] | ||||||||
Granted, Number | 300,000 | |||||||
RPUs Weighted Average Grant Date [Roll Forward] | ||||||||
Unrecognized compensation cost | $ | $ 2,000,000 | |||||||
2013 Convertible Phantom Units (CPUs) [Member] | ||||||||
Number of RPUs [Roll Forward] | ||||||||
Granted, Number | 300,000 | |||||||
[1] | Includes 613, 298 and 308 units canceled at the time of distribution for income tax liability payments we made on behalf of the restricted unit grantees for years ended December 31, 2015, 2014 and 2013, respectively. |
Unit Based Compensation Plans76
Unit Based Compensation Plans - Director Restricted Phantom Units (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Weighted Average Fair Value [Roll Forward] | |||
Unit-based compensation expense | $ 26,805 | $ 23,387 | $ 19,955 |
Director Restricted Phantom Units [Member] | |||
Number of Units [Roll Forward] | |||
Outstanding, beginning of period, Number | 78 | 67 | 48 |
Granted | 160 | 43 | 38 |
Vested | (37) | (32) | (19) |
Outstanding, end of period, Number | 201 | 78 | 67 |
Weighted Average Fair Value [Roll Forward] | |||
Outstanding, beginning of period, Weighted Average Fair Value | $ 20.44 | $ 20.69 | $ 20.43 |
Granted, Weighted Average Exercise Price | 6.56 | 20.29 | 20.98 |
Vested, Weighted Average Exercise Price | 20.35 | 20.77 | 20.63 |
Outstanding, end of period, Weighted Average Fair Value | $ 9.42 | $ 20.44 | $ 20.69 |
Unit-based compensation expense | $ 900 | $ 800 | $ 700 |
Unrecognized compensation cost | $ 1,000 | ||
Award vesting period | 2 years |
Unit Based Compensation Plans U
Unit Based Compensation Plans Unit Based Compensation Plans - CPUs (Details) $ in Thousands, shares in Millions | 1 Months Ended | 12 Months Ended | |||||
Nov. 30, 2014$ / units | Oct. 31, 2014$ / units | Nov. 30, 2013$ / units | Feb. 28, 2013$ / units | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)$ / unitsshares | Dec. 31, 2013USD ($)$ / unitsshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The amendment to the CPU agreements, commencing with the date of the amendment, now limits the multiplier to “1.” As a result at vesting, CPUs for each award will convert to Common Units on a 1:1 basis. In addition, the amendment provided for the forfeiture from the date of grant to the date of the amendment of previously credited PDRs to each executive. | the number of CUEs per CPU over the three year life of the agreement could be reduced to a minimum of zero or be multiplied by a maximum of 4.768 times based on the Partnership’s distribution levels. | |||||
Price Per Common Unit | $ / units | 14.73 | 18.64 | 18.22 | 19.86 | |||
Unit-based compensation expense | $ 26,805 | $ 23,387 | $ 19,955 | ||||
2014 Convertible Phantom Units (CPUs) [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted, Number | shares | 0.3 | ||||||
Unrecognized compensation cost | $ 2,000 | ||||||
2013 Convertible Phantom Units (CPUs) [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted, Number | shares | 0.3 | ||||||
Convertible Phantom Units (CPUs) [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Price Per Common Unit | $ / units | 20.29 | 20.98 | |||||
Unit-based compensation expense | $ 4,300 | $ 2,300 |
Retirement Plan (Details)
Retirement Plan (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Compensation and Retirement Disclosure [Abstract] | |||
Defined Contribution Plan, Vesting Period | P5Y | ||
Defined Contribution Plan, Cost Recognized | $ 3.6 | $ 3.7 | $ 2 |
Significant Customers (Details)
Significant Customers (Details) - 10% or More of Sales Revenue - Customer Concentration Risk [Member] | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Shell Trading [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Sales Revenue | 24.00% | 22.00% | 15.00% |
Plains Marketing and Transportation [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Sales Revenue | 12.00% | ||
Phillips 66 [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Sales Revenue | 10.00% | 15.00% | |
Marathon Oil [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Sales Revenue | 10.00% |
Restructuring Costs (Details)
Restructuring Costs (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2015employee | Mar. 31, 2015employee | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Restructuring Cost and Reserve [Line Items] | |||||
Restructuring Costs | $ 6,400 | ||||
Severance Costs | 4,800 | ||||
Unit-based compensation expense | 26,805 | $ 23,387 | $ 19,955 | ||
Other Restructuring Costs | $ 300 | ||||
One-time Termination Benefits [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Restructuring and Related Cost, Number of Positions Eliminated | employee | 8 | 37 |
Subsequent Events (Details)
Subsequent Events (Details) | Feb. 15, 2016 | Jan. 28, 2016$ / shares | Jan. 15, 2016 | Jan. 04, 2016$ / shares | Dec. 31, 2015$ / shares |
Preferred Units [Member] | |||||
Subsequent Event [Line Items] | |||||
Distribution Made to Limited Partner, Annual Distribution, Per Unit | $ 2.0625 | ||||
Preferred Units [Member] | Subsequent Event [Member] | |||||
Subsequent Event [Line Items] | |||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.171875 | $ 0.171875 | |||
Preferred Units B [Member] | Subsequent Event [Member] | |||||
Subsequent Event [Line Items] | |||||
Distribution Made to Limited Partner, Unit Distributions Declared, Per Unit | 0.006666 | 0.006666 |