Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Nov. 04, 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-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 211,884,150 |
Unaudited Consolidated Balance
Unaudited Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash | $ 12,091 | $ 12,628 |
Accounts and other receivables, net | 135,479 | 166,436 |
Current derivative instrument assets | 400,857 | 408,151 |
Related party receivables (note 4) | 2,069 | 2,462 |
Inventory | 3,371 | 3,727 |
Prepaid expenses | 12,654 | 7,304 |
Total current assets | 566,521 | 600,708 |
Equity investments | 6,473 | 6,463 |
Property, plant and equipment | ||
Oil and natural gas properties | 7,908,709 | 7,736,409 |
Other property, plant and equipment (note 2) | 141,047 | 60,533 |
Property, Plant and Equipment, Gross | 8,049,756 | 7,796,942 |
Accumulated depletion and depreciation (note 5) | (3,161,636) | (1,342,741) |
Net property, plant and equipment | 4,888,120 | 6,454,201 |
Other long-term assets | ||
Intangibles, net | 1,538 | 8,336 |
Goodwill (note 5) | 0 | 92,024 |
Derivative instruments (note 3) | 267,681 | 319,560 |
Other long-term assets (note 6) | 119,715 | 157,042 |
Total assets | 5,850,048 | 7,638,334 |
Current liabilities | ||
Accounts payable | 63,921 | 129,270 |
Current portion of long-term debt (note 7) | 603 | 105,000 |
Derivative instruments (note 3) | 5,289 | 5,457 |
Distributions payable | 733 | 733 |
Current portion of asset retirement obligation (note 9) | 2,390 | 4,948 |
Revenue and royalties payable | 42,454 | 40,452 |
Wages and salaries payable | 22,264 | 22,322 |
Accrued interest payable | 42,989 | 20,672 |
Production and property taxes payable | 30,838 | 25,207 |
Other current liabilities | 6,644 | 7,495 |
Total current liabilities | 218,125 | 361,556 |
Credit facility | 1,253,000 | 2,089,500 |
Senior notes, net | 1,788,466 | 1,156,560 |
Other long-term debt | 2,397 | 1,100 |
Total long-term debt (note 7) | 3,043,863 | 3,247,160 |
Deferred income taxes | 2,269 | 2,575 |
Asset retirement obligation (note 9) | 247,317 | 233,463 |
Derivative instruments (note 3) | 1,421 | 2,269 |
Other long-term liabilities (note 10) | 24,615 | 25,135 |
Total liabilities | $ 3,537,610 | $ 3,872,158 |
Commitments and contingencies (note 11) | ||
Equity | ||
Series A preferred units, 8.0 million units issued and outstanding at each of September 30, 2015 and December 31, 2014 (note 12) | $ 193,215 | $ 193,215 |
Series B preferred units, 48.0 million and 0 units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12) | 347,454 | 0 |
Common units, 211.8 million and 210.9 million units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12) | 1,765,689 | 3,566,468 |
Accumulated other comprehensive loss (note 13) | (576) | (392) |
Total partners' equity | 2,305,782 | 3,759,291 |
Noncontrolling interest | 6,656 | 6,885 |
Total equity | 2,312,438 | 3,766,176 |
Total liabilities and equity | $ 5,850,048 | $ 7,638,334 |
Balance Sheet Parentheticals
Balance Sheet Parentheticals - shares shares in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Preferred Units [Member] | ||
Common units issued and outstanding | 8 | 8 |
Preferred Units B [Member] | ||
Common units issued and outstanding | 48 | 0 |
Common Units [Member] | ||
Common units issued and outstanding | 211.8 | 210.9 |
Unaudited Consolidated Statemen
Unaudited Consolidated Statements of Operations shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015USD ($)$ / unitsshares | Sep. 30, 2014USD ($)$ / unitsshares | Sep. 30, 2015USD ($)$ / unitsshares | Sep. 30, 2014USD ($)$ / unitsshares | |
Revenues and other income items | ||||
Oil, natural gas and natural gas liquid sales | $ 153,325 | $ 216,146 | $ 505,584 | $ 658,753 |
Gain (loss) on commodity derivative instruments, net (note 3) | 253,012 | 146,171 | 296,772 | (21,057) |
Other revenue, net | 5,922 | 1,585 | 18,895 | 4,240 |
Total revenues and other income items | 412,259 | 363,902 | 821,251 | 641,936 |
Operating costs and expenses | ||||
Operating costs | 115,135 | 82,904 | 348,950 | 248,161 |
Depletion, depreciation and amortization | 117,464 | 72,671 | 336,735 | 204,417 |
Impairment of oil and natural gas properties (note 5) | 1,440,167 | 29,434 | 1,499,280 | 29,434 |
Impairment of goodwill (note 5) | 0 | 0 | 95,947 | 0 |
General and administrative expenses | 23,276 | 18,737 | 78,400 | 53,886 |
Restructuring costs (note 15) | (278) | 0 | 6,413 | 0 |
(Gain) loss on sale of assets | (7,459) | (63) | (7,322) | 357 |
Total operating costs and expenses | 1,688,305 | 203,683 | 2,358,403 | 536,255 |
Operating (loss) income | (1,276,046) | 160,219 | (1,537,152) | 105,681 |
Interest expense, net of capitalized interest | 50,919 | 29,494 | 151,988 | 90,360 |
Loss on interest rate swaps (note 3) | 996 | 0 | 3,411 | 0 |
Other income, net | (137) | (450) | (579) | (1,223) |
(Loss) income before taxes | (1,327,824) | 131,175 | (1,691,972) | 16,544 |
Income tax expense | 14 | 532 | 365 | 384 |
Net (loss) income | (1,327,838) | 130,643 | (1,692,337) | 16,160 |
Less: Net income attributable to noncontrolling interest | 91 | 0 | 124 | 0 |
Net (loss) income attributable to the partnership | (1,327,929) | 130,643 | (1,692,461) | 16,160 |
Less: Distributions to Series A preferred unitholders | 4,125 | 4,125 | 12,375 | 5,958 |
Less: Non-cash distributions to Series B preferred unitholders | 7,145 | 0 | 13,553 | 0 |
Less: Net (loss) income attributable to participating units | (31,662) | 1,868 | (40,612) | 40 |
Net (loss) income attributable to common unitholders | $ (1,307,537) | $ 124,650 | $ (1,677,777) | $ 10,162 |
Basic net income (loss) per unit (in dollars per unit) | $ / units | (6.17) | 1.03 | (7.94) | 0.08 |
Diluted net income (loss) per unit (in dollars per unit) | $ / units | (6.17) | 1.03 | (7.94) | 0.08 |
Basic | shares | 211,766 | 120,473 | 211,369 | 119,806 |
Diluted | shares | 211,766 | 121,250 | 211,369 | 120,544 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive (Loss) Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Statement of Comprehensive Income [Abstract] | |||||
Net (loss) income | $ (1,327,838) | $ 130,643 | $ (1,692,337) | $ 16,160 | |
Other comprehensive loss, net of tax: | |||||
Change in fair value of available-for-sale securities | [1] | (636) | 0 | (537) | 0 |
Total other comprehensive loss | (636) | 0 | (537) | 0 | |
Total comprehensive (loss) income | (1,328,474) | 130,643 | (1,692,874) | 16,160 | |
Less: Comprehensive loss attributable to noncontrolling interest | (303) | 0 | (229) | 0 | |
Comprehensive (loss) income attributable to the partnership | $ (1,328,171) | $ 130,643 | $ (1,692,645) | $ 16,160 | |
[1] | Net of income tax benefit of $0.4 million and $0.3 million for the three months and nine months ended September 30, 2015. |
Consolidated Statements of Com6
Consolidated Statements of Comprehensive (Loss) Income (Unaudited) Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2015 | Sep. 30, 2015 | |
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax | $ (0.4) | $ (0.3) |
Unaudited Consolidated Stateme7
Unaudited Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash flows from operating activities | ||
Net (loss) income | $ (1,692,337) | $ 16,160 |
Adjustments to reconcile to cash flows from operating activities: | ||
Depletion, depreciation and amortization | 336,735 | 204,417 |
Impairment of oil and natural gas properties | 1,499,280 | 29,434 |
Impairment of goodwill | 95,947 | 0 |
Unit-based compensation expense | 20,714 | 18,440 |
(Gain) loss on derivative instruments | (293,361) | 21,057 |
Derivative instrument settlement receipts (payments) | 351,518 | (34,228) |
Income from equity affiliates, net | (10) | 90 |
Deferred income taxes | (306) | 153 |
(Gain) loss on sale of assets | (7,322) | 357 |
Other | 14,348 | 5,172 |
Changes in net assets and liabilities | ||
Accounts receivable and other assets | 22,251 | (3,345) |
Inventory | 356 | (528) |
Net change in related party receivables and payables | 393 | 1,095 |
Accounts payable and other liabilities | 2,978 | 36,642 |
Net cash provided by operating activities | 351,184 | 294,916 |
Cash flows from investing activities | ||
Property acquisitions | (17,160) | (6,422) |
Capital expenditures | (226,718) | (293,275) |
Proceeds from sale of assets | 9,441 | 366 |
Proceeds from sale of available-for-sale securities | 3,631 | 0 |
Purchases of available-for-sale securities | (3,803) | 0 |
Other | (853) | (9,242) |
Net cash used in investing activities | (235,462) | (308,573) |
Cash flows from financing activities | ||
Proceeds from issuance of preferred units, net | 337,895 | 193,215 |
Proceeds from issuance of common units, net | 4,768 | 25,917 |
Distributions to preferred unitholders | (12,375) | (5,225) |
Distributions to common unitholders | (108,283) | (181,430) |
Proceeds from issuance of long-term debt, net | 1,203,400 | 693,000 |
Repayments of long-term debt | (1,512,500) | (707,000) |
Change in bank overdraft | (39) | (2,417) |
Debt issuance costs | (29,125) | (1,634) |
Net cash (used in) provided by financing activities | (116,259) | 14,426 |
(Decrease) increase in cash | (537) | 769 |
Cash beginning of period | 12,628 | 2,458 |
Cash end of period | $ 12,091 | $ 3,227 |
Organization and Basis of Prese
Organization and Basis of Presentation | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | Organization and Basis of Presentation The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2014 Annual Report. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at September 30, 2015 , our operating results for the three months and nine months ended September 30, 2015 and 2014 and our cash flows for the nine months ended September 30, 2015 and 2014 have been included. Operating results for the three months and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015 . The consolidated balance sheet at December 31, 2014 has been derived from the audited consolidated financial statements at that date but does not include all of the information and notes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and notes thereto included in our 2014 Annual Report. We follow the successful efforts method of accounting for oil and natural gas activities. Depletion, depreciation and amortization (“DD&A”) of proved oil and natural gas properties is computed using the units-of-production method, net of any estimated residual salvage values. Accounting Standards In April 2015, the Financial Accounting Standards Board (“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. 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 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 of these new requirements on our consolidated financial statements. |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 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 adjustment 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 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 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 asset retirement obligations (“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 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 $7.5 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. 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% . 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. 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 preliminary purchase price of $70.2 million (the “CO 2 Acquisition”), subject to customary purchase price adjustments, of which $14.3 million was paid in cash during the three months ended March 31, 2015, and $0.2 million was paid in cash during the three months ended June 30, 2015 and no amount was paid in cash during the three months ended September 30, 2015. The preliminary 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 2014 and reclassified from other long-term assets to other property, plant and equipment during the nine months ended September 30, 2015 and $5.1 million of intangibles reclassified from intangibles to other property, plant and equipment during the nine months ended September 30, 2015) and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet. 2014 Acquisitions QR Energy, LP On November 19, 2014, we completed the previously announced 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 Breitburn Operating LP (“BOLP”), its wholly-owned subsidiary. In connection with the QRE Merger, we acquired a 59% controlling interest in East Texas Salt Water Disposal Company (“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. Under the terms of the Merger Agreement, we issued a total of approximately 71.5 million common units representing limited partner interests (“Common Units”) to holders of outstanding QRE common units and QRE Class B Units. In addition, we paid a total of $350 million to holders of QRE Class C Units. The initial purchase price, subject to customary purchase price adjustments, for the QRE Merger 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 ) Noncontrolling interest (7,173 ) $ 1,408,434 The initial purchase price allocation was determined by management with the assistance of outside valuation consulting firms. While the initial valuation and purchase price allocation have been completed, circumstances may arise in the future that could lead to adjustments to the valuation and/or allocation. If adjustments are required, they would be recorded no later than one year from the acquisition date. We recognized goodwill of $95.9 million as part of the initial purchase price allocation. See Note 5 for a discussion of impairment of goodwill. In connection with the QRE Merger, on November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC. 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. 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. Pro Forma (unaudited) The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results include adjustments 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 acquisition, 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 acquisition. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2014. The Antares Acquisition in 2014 and the CO 2 Acquisition in 2015 were not included in the pro forma information as their results for the periods presented were immaterial. 2014 Pro Forma Three Months Ended Nine Months Ended Thousands of dollars, except per unit amounts September 30, 2014 September 30, 2014 Revenues $ 564,321 $ 1,009,362 Net income attributable to the partnership 211,356 45,286 Net income per common unit: Basic $ 1.00 $ 0.19 Diluted $ 0.99 $ 0.19 |
Financial Instruments
Financial Instruments | 9 Months Ended |
Sep. 30, 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 price volatilities and to assist with stabilizing cash flows and distributions. 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 The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These differentials often result in a lack of adequate correlation to enable these derivative instruments to qualify as cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes, and instead we recognize changes in fair value immediately in earnings. We had the following commodity derivative contracts in place at September 30, 2015 : Year 2015 2016 2017 2018 2019 Oil Positions: Fixed Price Swaps - NYMEX WTI Volume (Bbl/d) 20,043 15,504 13,519 493 — Average Price ($/Bbl) $ 93.27 $ 88.07 $ 85.05 $ 82.20 $ — Fixed Price Swaps - ICE Brent Volume (Bbl/d) 3,300 4,300 298 — — Average Price ($/Bbl) $ 97.73 $ 95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d) 2,025 1,500 — — — Average Floor Price ($/Bbl) $ 90.00 $ 80.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 111.73 $ 102.00 $ — $ — $ — Collars - ICE Brent Volume (Bbl/d) 500 500 — — — Average Floor Price ($/Bbl) $ 90.00 $ 90.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 109.50 $ 101.25 $ — $ — $ — Puts - NYMEX WTI Volume (Bbl/d) 500 1,000 — — — Average Price ($/Bbl) $ 90.00 $ 90.00 $ — $ — $ — Total: Volume (Bbl/d) 26,368 22,804 13,817 493 — Average Price ($/Bbl) $ 93.46 $ 89.01 $ 85.32 $ 82.20 $ — Natural Gas Positions: Fixed Price Swaps - MichCon City-Gate Volume (MMBtu/d) 17,500 29,000 24,000 14,000 8,000 Average Price ($/MMBtu) $ 4.26 $ 3.91 $ 3.71 $ 3.15 $ 3.20 Fixed Price Swaps - Henry Hub Volume (MMBtu/d) 54,891 36,050 19,016 1,870 — Average Price ($/MMBtu) $ 4.84 $ 4.24 $ 4.43 $ 4.15 $ — Collars - Henry Hub Volume (MMBtu/d) 18,000 630 595 — — Average Floor Price ($/MMBtu) $ 5.00 $ 4.00 $ 4.00 — — Average Ceiling Price ($/MMBtu) $ 7.48 $ 5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume (MMBtu/d) 1,920 11,350 10,445 — — Average Price ($/MMBtu) $ 4.78 $ 4.00 $ 4.00 $ — $ — Deferred Premium ($/MMBtu) $ 0.64 (a) $ 0.66 (b) $ 0.69 (c) $ — $ — Total: Volume (MMBtu/d) 92,311 77,030 54,056 15,870 8,000 Average Price ($/MMBtu) $ 4.76 $ 4.08 $ 4.02 $ 3.26 $ 3.20 (a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume. (b) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume. (c) Deferred premiums of $0.69 apply to 10,445 MMBtu/d of the 2017 volume. During the three months and nine months ended September 30, 2015 and 2014 , we did not enter into any derivative instruments that required pre-paid premiums. As of September 30, 2015 , premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond September 30, 2015 were as follows: Year Thousands of dollars 2015 2016 2017 Oil $ 1,180 $ 7,438 $ 734 Natural gas $ 501 $ 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 September 30, 2015 . These contracts were novated to us in November 2014 in connection with the QRE Merger: Year 2015 2016 Fixed Rate Swaps - LIBOR Notional Amount (thousands of dollars) $ 374,031 $ 410,000 Average Fixed Rate 1.64 % 1.72 % We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes. Fair Value of Financial Instruments The following table presents the fair value of our 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 September 30, 2015 Assets Current assets - derivative instruments $ 358,741 $ 44,281 $ — $ (2,165 ) $ 400,857 Other long-term assets - derivative instruments 240,177 30,886 — (3,382 ) 267,681 Total assets 598,918 75,167 — (5,547 ) 668,538 Liabilities Current liabilities - derivative instruments (40 ) (2,214 ) (5,200 ) 2,165 (5,289 ) Long-term liabilities - derivative instruments (43 ) (3,748 ) (1,012 ) 3,382 (1,421 ) Total liabilities (83 ) (5,962 ) (6,212 ) 5,547 (6,710 ) Net assets (liabilities) $ 598,835 $ 69,205 $ (6,212 ) $ — $ 661,828 As of December 31, 2014 Assets Current assets - derivative instruments $ 350,351 $ 58,246 $ — $ (446 ) $ 408,151 Other long-term assets - derivative instruments 296,441 29,649 210 (6,740 ) 319,560 Total assets 646,792 87,895 210 (7,186 ) 727,711 Liabilities Current liabilities - derivative instruments (214 ) (563 ) (5,126 ) 446 (5,457 ) Long-term liabilities - derivative instruments (1,520 ) (5,220 ) (2,269 ) 6,740 (2,269 ) Total liabilities (1,734 ) (5,783 ) (7,395 ) 7,186 (7,726 ) Net assets (liabilities) $ 645,058 $ 82,112 $ (7,185 ) $ — $ 719,985 (a) Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets. The following table presents gains and losses on derivative instruments not designated as hedging instruments: Thousands of dollars Oil Commodity Derivatives (a) Natural Gas Commodity Derivatives (a) Interest Rate Derivatives (b) Total Financial Instruments Three Months Ended September 30, 2015 Net gain (loss) $ 234,158 $ 18,854 $ (996 ) $ 252,016 Three Months Ended September 30, 2014 Net gain $ 133,666 $ 12,505 $ — $ 146,171 Nine Months Ended September 30, 2015 Net gain (loss) $ 261,360 $ 35,412 $ (3,411 ) $ 293,361 Nine Months Ended September 30, 2014 Net loss $ (15,553 ) $ (5,504 ) $ — $ (21,057 ) (a) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. (b) Included in 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 that are observable other than quoted prices that are included within 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 derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of September 30, 2015 , and December 31, 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 three months and nine months ended September 30, 2015 and 2014 . 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 Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts we receive from counterparties on a monthly basis and also use a third-party validation firm for a portion of our portfolio. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements. The model we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments is a standard option pricing model. Level 2 inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity futures price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, futures 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 QRE Merger are estimated using a combined income and market valuation methodology based upon futures commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate 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 tables set 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. 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 September 30, 2015 Assets (liabilities) Crude Oil Crude oil swaps $ — $ 548,524 $ — $ 548,524 Crude oil collars — — 33,477 33,477 Crude oil puts — — 16,835 16,835 Natural Gas Natural gas swaps — 55,075 — 55,075 Natural gas collars — — 4,490 4,490 Natural gas puts — — 9,639 9,639 Interest rate swaps Interest rate swaps — (6,212 ) — (6,212 ) Available-for-sale securities Equities 2,419 — — 2,419 Mutual funds 11,304 — — 11,304 Exchange traded funds 4,805 — — 4,805 Net assets $ 18,528 $ 597,387 $ 64,441 $ 680,356 Thousands of dollars Level 1 Level 2 Level 3 Total As of December 31, 2014 Assets (liabilities) Crude Oil Crude oil swaps $ — $ 583,648 $ — $ 583,648 Crude oil collars — — 44,405 44,405 Crude oil puts — — 17,005 17,005 Natural gas commodity derivatives 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 tables set forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: Three Months Ended September 30, 2015 2014 Thousands of dollars Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 41,001 $ 15,010 $ 1,540 $ 840 Derivative instrument settlements (b) 11,903 4,050 — 347 (Loss) gain (b)(c) (2,592 ) (4,931 ) 5,529 (222 ) Ending balance $ 50,312 $ 14,129 $ 7,069 $ 965 Nine Months Ended September 30, 2015 2014 Thousands of dollars Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 61,410 $ 19,892 $ 8,957 $ 1,848 Derivative instrument settlements (b) 31,454 11,854 — 389 Loss (b)(c) (42,552 ) (17,617 ) (1,888 ) (1,272 ) Ending balance $ 50,312 $ 14,129 $ 7,069 $ 965 (a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, purchases or issuances. (b) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. (c) Represents loss on mark-to-market of derivative instruments. For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2015 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars September 30, 2015 Technique Unobservable Input Range Oil Options $ 50,312 Option Pricing Model Oil forward commodity prices $45.09/Bbl - $56.04/Bbl Oil volatility 27.94% - 44.82% Own credit risk 5% Natural Gas Options 14,129 Option Pricing Model Gas forward commodity prices $2.52/MMBtu - $3.29/MMBtu Gas volatility 22.58% - 58.91% Own credit risk 5% Total $ 64,441 For Level 3 derivative instruments 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 September 30, 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 Third Amended and Restated Credit Agreement. Our Third Amended and Restated 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 September 30, 2015 , each of these financial institutions had an investment grade credit rating. As of September 30, 2015 , our largest derivative asset balances were with Wells Fargo Bank, N.A. , Credit Suisse Energy LLC , JP Morgan Chase Bank N.A. and Barclays Bank PLC, which accounted for approximately 19% , 11% , 11% and 11% of our net derivative asset balances, respectively. |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Breitburn Management Company LLC (“Breitburn Management”), our wholly-owned subsidiary, 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 Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P. (“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 three months and nine months ended September 30, 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. At December 31, 2016, the ASA is subject to renegotiation. Effective on April 8, 2015, the closing date of private offerings of senior secured second lien notes and perpetual convertible preferred units (see Note 7 and Note 12, respectively), Kurt A. Talbot, 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 (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. At September 30, 2015 and December 31, 2014 , we had a current receivable of $1.6 million and $2.4 million , respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties. For the three months ended September 30, 2015 and 2014 , the monthly charges to PCEC for indirect expenses totaled $2.1 million in each period, and charges for direct expenses including payroll and administrative costs totaled $2.3 million and $3.8 million , respectively. For the nine months ended September 30, 2015 and 2014 , the monthly charges to PCEC for indirect expenses totaled $6.3 million in each period, and charges for direct expenses including payroll and administrative costs totaled $7.3 million and $8.9 million , respectively. At September 30, 2015 and December 31, 2014 , we had receivables of $0.5 million and $0.1 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf. |
Impairments
Impairments | 9 Months Ended |
Sep. 30, 2015 | |
Impairments [Abstract] | |
Impairments | Impairments Oil and Natural Gas Properties We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their carrying value may not be recoverable. Generally, management does not view temporarily low commodity prices as a sole indicator that an impairment event has occurred as crude oil and natural gas prices have a history of significant volatility. Determination as to whether and how much an asset is impaired involves subjectivity and management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, the outlook for market supply and demand conditions for oil and natural gas, and other factors. For purposes of assessing our oil and gas properties for potential impairment, management reviews the expected undiscounted future cash flows for our total proved and risk-adjusted probable and possible reserves. The undiscounted cash flow review includes inputs such as applicable NYMEX strip prices, estimated basis price differentials, expenses and capital estimates, and escalation factors. Management also considers the impact future price changes are likely to have on our future operating plans. If we determine that an impairment charge for a property is warranted, an impairment charge is recorded for the amount that the property’s carrying value exceeds the amount of its estimated discounted future cash flows. For purposes of calculating an impairment charge, estimated discounted future cash flows are determined by using applicable basis adjusted five-year NYMEX strip prices and escalated along with expenses and capital starting in 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. The associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 10% . 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. Non-cash impairments of proved properties totaled $1.4 billion and $1.5 billion for the three months and nine months ended September 30, 2015 , respectively. For the three months ended September 30, 2015 , we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $49.7 million for our Permian properties, $17.4 million in the Rockies and $12.2 million for our Mid-Continent properties, primarily related to the impact of the drop in commodity strip prices on our projected future net revenues. For the nine months ended September 30, 2015 , we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $82.8 million for our Permian properties, $34.1 million for our Rockies natural gas properties and $21.5 million for our Mid-Continent properties primarily due to the impact of the drop in commodity strip prices on our projected future net revenues during the third quarter and the impact of the decrease in oil and natural gas prices on certain of our low operating margin properties during the first quarter. Impairments totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in the Rockies. The carrying values of the properties were reduced to their estimated fair values using level 3 inputs. Additional impairments may be recognized in the fourth quarter of 2015 should commodity prices decline further. 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 this period, whereas unfavorable changes might have caused an additional unknown number of other assets to become 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 charged to impairment. 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. 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 QRE Merger (see Note 2). 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 three months ended June 30, 2015, to reduce the carrying value of goodwill to zero. |
Other Assets
Other Assets | 9 Months Ended |
Sep. 30, 2015 | |
Other Assets [Abstract] | |
Other Assets | Other Assets As of September 30, 2015 , and December 31, 2014 , our other long-term assets were $119.7 million and $157.0 million , respectively, consisting of the following: As of Thousands of dollars September 30, 2015 December 31, 2014 Debt issuance costs $ 62,341 $ 52,787 Available-for-sale securities 18,528 19,345 Deposit for Jay Field net profit interest obligation 18,263 18,263 Property reclamation deposit 10,735 10,735 CO 2 supply advances and deposits — 50,792 Other 9,848 5,120 Total $ 119,715 $ 157,042 The $62.3 million of debt issuance costs at September 30, 2015 included $21.6 million in debt issuance costs relating to the Senior Secured Notes (as defined below) issued on April 8, 2015, partially offset by the write-off of $10.6 million of debt issuance costs relating to the reduction of our borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing. See Note 7 for a discussion of the Senior Secured Notes and the EIG financing. At each of September 30, 2015 and December 31, 2014 , we had a deposit for a net profits interest obligation for the Jay Field in Florida of $18.3 million (assumed in the QRE Merger) and a property reclamation deposit for future abandonment and remediation obligations for the Jay Field of $10.7 million . At September 30, 2015 and December 31, 2014 , we had zero and $50.8 million , respectively, in CO 2 supply advances and deposits for our Mid-Continent properties. In connection with the CO 2 Acquisition, during the nine months ended September 30, 2015, we reclassified $50.8 million of CO 2 supply advances and deposits from other long-term assets to other property, plant and equipment on the consolidated balance sheet. See Note 2 for a discussion of the CO 2 Acquisition. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2015 | |
Long-term Debt, Unclassified [Abstract] | |
Long-Term Debt | Long-Term Debt Our long-term debt is detailed in the following table: As of Thousands of dollars September 30, 2015 December 31, 2014 Credit facility $ 1,253,000 $ 2,194,500 Promissory note 3,000 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 (16,534 ) 1,560 Total debt 3,044,466 3,352,160 Less: current portion of long-term debt (603 ) (105,000 ) Total long-term debt $ 3,043,863 $ 3,247,160 Credit Facility On April 8, 2015, in connection with financing and related party transactions with EIG Global Energy Partners, we entered into the First Amendment to the Third Amended and Restated Credit Agreement (the “First Amendment”). 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). As of September 30, 2015 , BOLP, our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had 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. Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. Historically, our borrowing base has been redetermined semi-annually. As of September 30, 2015 and December 31, 2014 , our borrowing base was $1.8 billion and $2.5 billion , respectively. Our next borrowing base redetermination is scheduled for April 2016. As of September 30, 2015 and December 31, 2014 , we had $1.25 billion and $2.19 billion , respectively, in indebtedness outstanding under our credit facility. At September 30, 2015 , the 1-month LIBOR interest rate plus an applicable spread was 2.4511% on the 1-month LIBOR portion of $1.30 billion and the prime rate plus an applicable spread was 4.50% on the prime portion of $5.0 million . At September 30, 2015 and December 31, 2014 , we had $23.6 million and $33.5 million , respectively, of unamortized debt issuance costs related to our credit facility. During the three and nine months ended September 30, 2015, we had a write-off of zero and $10.6 million , respectively, 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. As of September 30, 2015 and December 31, 2014 , we were in compliance with our credit facility’s covenants. 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 outstanding borrowings 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, 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 some cases, ceased to provide any new funding. If the borrowing base determination in April 2016 results in a borrowing base deficiency and we cannot access the capital markets and repay debt under our credit facility, we may be unable to continue to pay distributions to our unitholders and may take other actions to reduce costs and to raise funds to repay debt, such as selling assets or monetizing derivative contracts. 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 September 30, 2015 , our Senior Secured Notes had a carrying value of $631.9 million , net of unamortized discount of $18.1 million . As of September 30, 2015 , the fair value of our Senior Secured Notes was estimated to be approximately $612 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 September 30, 2015 and December 31, 2014 , we had $21.6 million and zero , respectively, of unamortized debt issuance costs related to our Senior Secured Notes. Senior Unsecured Notes As of September 30, 2015 , we had $305 million in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $301.9 million , net of unamortized discount of $3.1 million . In addition, as of September 30, 2015 , we had $850 million in aggregate principal amount of 7.875% senior notes due 2022 (the “2022 Senior Notes”), which had a carrying value of $854.6 million , net of unamortized premium of $4.6 million . Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October. At September 30, 2015 and December 31, 2014 , we had $17.1 million and $19.3 million , respectively, of unamortized debt issuance costs related to our 2020 Senior Notes and 2022 Senior Notes (together the “Senior Unsecured Notes”). As of September 30, 2015 , the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be approximately $138 million and $302 million , respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions. As of September 30, 2015 and December 31, 2014 , we were in compliance with the covenants under our Senior Unsecured Notes. Interest Expense Our interest expense is detailed as follows: Three Months Ended Nine Months Ended September 30, September 30, Thousands of dollars 2015 2014 2015 2014 Credit agreement (including commitment fees) $ 8,828 $ 4,539 $ 32,422 $ 14,886 Senior Unsecured Notes 23,311 23,311 69,933 69,933 Senior Secured Notes 15,031 — 28,893 — Amortization of net discount/premium and deferred issuance costs (a) 3,816 1,765 20,885 5,779 Capitalized interest (67 ) (121 ) (145 ) (238 ) Total $ 50,919 $ 29,494 $ 151,988 $ 90,360 (a) The three months and nine months ended September 30, 2015 include a write-off of zero and $10.6 million , respectively, of debt issuance costs relating to the reduction of our credit facility borrowing base. |
Condensed Consolidating Financi
Condensed Consolidating Financial Statements | 9 Months Ended |
Sep. 30, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Statements | Condensed Consolidating Financial Statements We and Breitburn Finance Corporation (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 the Senior Notes, and our only non-guarantor subsidiaries, Breitburn Collingwood Utica LLC 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 Corporation, the subsidiary co-issuer that does not guarantee the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned and have guaranteed the Senior Notes; and all of the guarantees are full, unconditional, joint and several. Each guarantee of each of the Senior Notes is subject to release in the following customary circumstances except as noted: (1) a disposition of all or substantially all the assets of the guarantor subsidiary (including by way of 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 as defined in the applicable indenture (applicable to the Senior Unsecured Notes only), (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 (applicable to the Senior Unsecured Notes only). |
Asset Retirement Obligation
Asset Retirement Obligation | 9 Months Ended |
Sep. 30, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligation | Asset Retirement Obligations 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 of approximately 10% 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 period ended September 30, 2015 , and the year ended December 31, 2014 are presented in the following table: Nine Months Ended Year Ended Thousands of dollars September 30, 2015 December 31, 2014 Carrying amount, beginning of period $ 238,411 $ 123,769 Acquisitions 796 95,800 Divested properties (261 ) — Liabilities incurred 2,140 4,020 Liabilities settled (6,679 ) (1,708 ) Revisions 2,703 6,770 Accretion expense 12,597 9,760 Carrying amount, end of period 249,707 238,411 Less: current portion of ARO (2,390 ) (4,948 ) Non-current portion of ARO $ 247,317 $ 233,463 |
Pension and Postretirement Bene
Pension and Postretirement Benefits Pension and Postretirement Benefits | 9 Months Ended |
Sep. 30, 2015 | |
Pensions and Postretirement Benefits [Abstract] | |
Pensions and Postretirement Benefits | Pensions and Postretirement Benefits We acquired ETSWDC on November 19, 2014 in connection with the QRE Merger. ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory postretirement benefit plan covering substantially all ETSWDC employees who were employed prior to March 31, 2008. The components of net periodic benefit costs reflected in our consolidated statements of operations for the three months and nine months ended September 30, 2015 consist of the following: Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Service cost $ 68 $ 8 $ 203 $ 25 Interest cost 254 39 761 117 Expected return on plan assets (336 ) (24 ) (1,007 ) (74 ) Net periodic (income) benefit costs $ (14 ) $ 23 $ (43 ) $ 68 |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies 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 September 30, 2015 and December 31, 2014 , we had approximately $26.4 million and $21.1 million , respectively, of surety bonds. At each of September 30, 2015 and December 31, 2014 , we had approximately $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. |
Partners' Equity
Partners' Equity | 9 Months Ended |
Sep. 30, 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 $337.4 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. For the three months and nine months ended September 30, 2015 , we elected to pay our Series B Preferred Unit distributions 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. During the three months and nine months ended September 30, 2015 , we declared distributions on our Series B Preferred Units of $0.02000 and $0.03489 Series B Preferred Units per unit, respectively, in the form of 786,634 and 1,361,925 Series B Preferred Units, respectively, and 163,314 and 284,898 Common Units, respectively. During the three months and nine months ended September 30, 2015 , we recognized $7.2 million and $13.6 million , respectively, 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 Series A Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million . The Series A Preferred Units rank senior to the Common Units and on parity with the Series B Preferred Units with respect to the payment of current distributions. 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 three months and nine months ended September 30, 2015 , we recognized $4.1 million and $12.4 million , respectively, of accrued distributions on the Series A Preferred Units, which are included in distributions to Series A preferred unitholders on the consolidated statements of operations. During the three months and nine months ended September 30, 2014 , we recognized $4.1 million and $6.0 million , respectively, of accrued distributions on the Series A Preferred Units. Common Units At each of September 30, 2015 and December 31, 2014 , we had approximately 211.8 million and 210.9 million , respectively, of Common Units outstanding. 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 three months ended March 31, 2015, June 30, 2015 and September 30, 2015 , we sold zero , 543,845 and zero Common Units, respectively, under the Equity Distribution Agreement for net proceeds of zero , $3.4 million and zero , respectively. During the three months ended March 31, 2014, June 30, 2014 and September 30, 2014, we sold 25,300 , 976,611 and 269,774 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $0.5 million , $19.7 million and $6.0 million , respectively. During the three months and nine months ended September 30, 2015 , we issued 163,314 and 284,898 Common Units, respectively, to a Series B Preferred unitholder that elected to receive its paid in kind distributions in Common Units. During each of the three months and nine months ended September 30, 2014 , we issued zero Common Units related to the Series B Preferred Units paid in kind distribution. During the three months and nine months ended September 30, 2015 , we issued zero and less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2015. During the three months and nine months ended September 30, 2014 , we issued zero Common Units and less than 0.1 million Common Units, respectively, to non-employee directors for RPUs that vested in January 2014. At September 30, 2015 and December 31, 2014 , there were approximately 5.9 million and 1.8 million , respectively, of units outstanding under our long-term incentive plan (“LTIP”) that were eligible to be paid in Common Units upon vesting. During the three months ended September 30, 2015 , we paid three monthly cash distributions totaling approximately $26.5 million , or $0.1250 per Common Unit. During the nine months ended September 30, 2015 , we paid nine monthly cash distributions totaling approximately $105.6 million , or $0.4999 per Common Unit. During the three months ended September 30, 2014 , we paid cash distributions of approximately $60.5 million , or $0.5025 per Common Unit. During the nine months ended September 30, 2014 , we paid cash distributions of approximately $178.7 million , or $1.4925 per Common Unit. During the three months and nine months ended September 30, 2015 , in addition to the distributions paid to holders of our Common Units, we paid $0.6 million and $2.7 million , respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP. During the three months and nine months ended September 30, 2014 , we paid $0.9 million and $2.8 million , respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP. 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 dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested 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 loss per common unit. The following is a reconciliation of net loss and weighted average units for calculating basic net loss per common unit and diluted net loss per common unit. Three Months Ended Nine Months Ended September 30, September 30, Thousands, except per unit amounts 2015 2014 2015 2014 Net (loss) income attributable to the partnership $ (1,327,929 ) $ 130,643 $ (1,692,461 ) $ 16,160 Less: Net (loss) income attributable to participating units (31,662 ) 1,868 (40,612 ) 40 Distributions to Series A preferred unitholders 4,125 4,125 12,375 5,958 Non-cash distributions to Series B preferred unitholders 7,145 — 13,553 — Net (loss) income attributable to Common Unitholders $ (1,307,537 ) $ 124,650 $ (1,677,777 ) $ 10,162 Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands): Common Units 211,766 120,473 211,369 119,806 Dilutive units (a) — 777 — 738 Denominator for diluted net (loss) income per unit 211,766 121,250 211,369 120,544 Net (loss) income per common unit Basic $ (6.17 ) $ 1.03 $ (7.94 ) $ 0.08 Diluted $ (6.17 ) $ 1.03 $ (7.94 ) $ 0.08 (a) The three months and nine months ended September 30, 2015 exclude 749 and 724 , respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Loss | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Loss | Accumulated Other Comprehensive Loss Changes in accumulated other comprehensive loss by component, net of tax, for the three months and nine months ended September 30, 2015 were as follows: Three Months Ended September 30, 2015 Gain (loss) on Thousands of dollars Available-For-Sale Securities Postretirement Benefits Total Accumulated comprehensive loss attributable to the partnership as of June 30, 2015 $ (53 ) $ (280 ) $ (333 ) Other comprehensive loss before reclassification (637 ) — (637 ) Amounts reclassified from accumulated other comprehensive loss (a) — — — Net current period other comprehensive loss (637 ) — (637 ) Less: noncontrolling interest (394 ) — (394 ) Accumulated comprehensive loss attributable to the partnership as of September 30, 2015 $ (296 ) $ (280 ) $ (576 ) Nine Months Ended September 30, 2015 Gain (loss) on Thousands of dollars Available-For-Sale Securities Postretirement Benefits Total Accumulated comprehensive loss attributable to the partnership as of December 31, 2014 $ (112 ) $ (280 ) $ (392 ) Other comprehensive loss before reclassification (390 ) — (390 ) Amounts reclassified from accumulated other comprehensive loss (a) (147 ) — (147 ) Net current period other comprehensive income (537 ) — (537 ) Less: noncontrolling interest (353 ) — (353 ) Accumulated comprehensive loss attributable to the partnership as of September 30, 2015 $ (296 ) $ (280 ) $ (576 ) (a) Amounts were reclassified from accumulated other comprehensive loss to other expense (income), net on the consolidated statements of operations. |
Unit and Other Valuation-Based
Unit and Other Valuation-Based Compensation Plans | 9 Months Ended |
Sep. 30, 2015 | |
Share-based Compensation [Abstract] | |
Unit Based Compensation Plans | Unit Based Compensation Plans Unit-based compensation expense for the three months ended September 30, 2015 and 2014 was $6.2 million and $5.8 million , respectively, and for the nine months ended September 30, 2015 and 2014 was $20.7 million and $18.4 million respectively. Unit based compensation expense of $6.4 million for the three months ended September 30, 2015 was included in general and administrative expenses and a credit adjustment of $0.2 million was included in restructuring costs. Unit-based compensation expense of $19.4 million for the nine months ended September 30, 2015 was included in general and administrative expenses and $1.3 million was included in restructuring costs. See Note 15 for a discussion of restructuring costs. During the three months and nine months ended September 30, 2015 , the board of directors of our General Partner approved the grant of less than 0.1 million and 4.7 million RPUs and CPUs to employees of Breitburn Management under our LTIP, respectively. During the three months and nine months ended September 30, 2015 , our outside directors were issued zero and 0.2 million RPUs under our LTIP, respectively. The fair market value of the RPUs granted during 2015 for computing compensation expense under FASB Accounting Standards averaged $6.52 per unit. During each of the three months ended September 30, 2015 and 2014 , we paid zero for taxes withheld on RPUs. During the nine months ended September 30, 2015 and 2014 , we paid $0.7 million and $0.9 million for taxes withheld on RPUs. As of September 30, 2015 , we had $30.1 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from October 1, 2015 to December 31, 2017. For detailed information on our various compensation plans, see Note 18 to the consolidated financial statements included in our 2014 Annual Report. |
Restructuring Costs
Restructuring Costs | 9 Months Ended |
Sep. 30, 2015 | |
Restructuring Costs [Abstract] | |
Restructuring Costs | 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 connection with the reduction, we incurred a total cost of approximately $5.6 million , of which $4.9 million was recognized in the first quarter of 2015, which includes severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. In April 2015, we communicated further reductions to an additional 8 employees and incurred a total cost of approximately $1.1 million , which was recognized in the second quarter of 2015. Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions. Three Months Ended Nine Months Ended Thousands of dollars September 30, 2015 September 30, 2015 Severance payments — 4,768 Unit-based compensation expense (191 ) 1,343 Other termination costs (87 ) 302 Total (278 ) 6,413 |
Subsequent Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events On October 1, 2015, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the third quarter of 2015 at the rate of $0.04166 per Common Unit, which was paid on October 16, 2015 to the unitholders of record at the close of business on October 12, 2015. On October 30, 2015, we announced a cash distribution to holders of Common Units for the second monthly payment attributable to the third quarter of 2015 at the rate of $0.04166 per Common Unit, to be paid on November 13, 2015 to the unitholders of record at the close of business on November 9, 2015 . On October 1, 2015, we also declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on November 16, 2015 , to record holders of our Series A Preferred Units at the close of business on October 30, 2015. On October 30, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on December 15, 2015 to record holders of our Series A Preferred Units at the close of business on November 30, 2015. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit. On October 1, 2015 and October 30, 2015 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 October 15, 2015 and November 16, 2015, respectively, to record holders of Series B Preferred Units at the close of business on September 30, 2015 and October 30, 2015, respectively. In October 2015, we entered into several crude oil and natural gas swap contracts, increasing our NYMEX WTI crude oil swap portfolio by 2,000 Bbl/day for 2016 and 1,000 Bbl/day for each of 2017, 2018, and 2019 for prices ranging from $49.10 per Bbl to $56.35 per Bbl, and our Henry Hub natural gas swap portfolio by 6,000 MMBtu/day, 2,000 MMBtu/day, and 1,000 MMBtu/day for 2016, 2017 and 2018, respectively, for prices ranging from $2.67 per MMBtu to $2.99 per MMBtu and our MichCon natural gas swap portfolio by 3,500 MMBtu/day for 2018 at $2.91 per MMBtu and 2,000 MMBtu/day for 2019 at $2.95 per MMBtu. |
Acquisitions (Tables)
Acquisitions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The initial purchase price, subject to customary purchase price adjustments, for the QRE Merger 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 ) Noncontrolling interest (7,173 ) $ 1,408,434 |
Business Acquisition, Pro Forma Information | The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results include adjustments 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 acquisition, 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 acquisition. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2014. The Antares Acquisition in 2014 and the CO 2 Acquisition in 2015 were not included in the pro forma information as their results for the periods presented were immaterial. 2014 Pro Forma Three Months Ended Nine Months Ended Thousands of dollars, except per unit amounts September 30, 2014 September 30, 2014 Revenues $ 564,321 $ 1,009,362 Net income attributable to the partnership 211,356 45,286 Net income per common unit: Basic $ 1.00 $ 0.19 Diluted $ 0.99 $ 0.19 |
Financial Instruments - Interes
Financial Instruments - Interest Rate Swaps (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Financial Instruments [Abstract] | |
Schedule of Price Risk Derivatives | We had the following commodity derivative contracts in place at September 30, 2015 : Year 2015 2016 2017 2018 2019 Oil Positions: Fixed Price Swaps - NYMEX WTI Volume (Bbl/d) 20,043 15,504 13,519 493 — Average Price ($/Bbl) $ 93.27 $ 88.07 $ 85.05 $ 82.20 $ — Fixed Price Swaps - ICE Brent Volume (Bbl/d) 3,300 4,300 298 — — Average Price ($/Bbl) $ 97.73 $ 95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d) 2,025 1,500 — — — Average Floor Price ($/Bbl) $ 90.00 $ 80.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 111.73 $ 102.00 $ — $ — $ — Collars - ICE Brent Volume (Bbl/d) 500 500 — — — Average Floor Price ($/Bbl) $ 90.00 $ 90.00 $ — $ — $ — Average Ceiling Price ($/Bbl) $ 109.50 $ 101.25 $ — $ — $ — Puts - NYMEX WTI Volume (Bbl/d) 500 1,000 — — — Average Price ($/Bbl) $ 90.00 $ 90.00 $ — $ — $ — Total: Volume (Bbl/d) 26,368 22,804 13,817 493 — Average Price ($/Bbl) $ 93.46 $ 89.01 $ 85.32 $ 82.20 $ — Natural Gas Positions: Fixed Price Swaps - MichCon City-Gate Volume (MMBtu/d) 17,500 29,000 24,000 14,000 8,000 Average Price ($/MMBtu) $ 4.26 $ 3.91 $ 3.71 $ 3.15 $ 3.20 Fixed Price Swaps - Henry Hub Volume (MMBtu/d) 54,891 36,050 19,016 1,870 — Average Price ($/MMBtu) $ 4.84 $ 4.24 $ 4.43 $ 4.15 $ — Collars - Henry Hub Volume (MMBtu/d) 18,000 630 595 — — Average Floor Price ($/MMBtu) $ 5.00 $ 4.00 $ 4.00 — — Average Ceiling Price ($/MMBtu) $ 7.48 $ 5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume (MMBtu/d) 1,920 11,350 10,445 — — Average Price ($/MMBtu) $ 4.78 $ 4.00 $ 4.00 $ — $ — Deferred Premium ($/MMBtu) $ 0.64 (a) $ 0.66 (b) $ 0.69 (c) $ — $ — Total: Volume (MMBtu/d) 92,311 77,030 54,056 15,870 8,000 Average Price ($/MMBtu) $ 4.76 $ 4.08 $ 4.02 $ 3.26 $ 3.20 (a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume. (b) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume. (c) Deferred premiums of $0.69 apply to 10,445 MMBtu/d of the 2017 volume. |
Prepaid Derivative Premiums | As of September 30, 2015 , premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond September 30, 2015 were as follows: Year Thousands of dollars 2015 2016 2017 Oil $ 1,180 $ 7,438 $ 734 Natural gas $ 501 $ 952 $ — |
Schedule of Interest Rate Derivatives | 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 September 30, 2015 . These contracts were novated to us in November 2014 in connection with the QRE Merger: Year 2015 2016 Fixed Rate Swaps - LIBOR Notional Amount (thousands of dollars) $ 374,031 $ 410,000 Average Fixed Rate 1.64 % 1.72 % We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes. |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | Fair Value of Financial Instruments The following table presents the fair value of our 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 September 30, 2015 Assets Current assets - derivative instruments $ 358,741 $ 44,281 $ — $ (2,165 ) $ 400,857 Other long-term assets - derivative instruments 240,177 30,886 — (3,382 ) 267,681 Total assets 598,918 75,167 — (5,547 ) 668,538 Liabilities Current liabilities - derivative instruments (40 ) (2,214 ) (5,200 ) 2,165 (5,289 ) Long-term liabilities - derivative instruments (43 ) (3,748 ) (1,012 ) 3,382 (1,421 ) Total liabilities (83 ) (5,962 ) (6,212 ) 5,547 (6,710 ) Net assets (liabilities) $ 598,835 $ 69,205 $ (6,212 ) $ — $ 661,828 As of December 31, 2014 Assets Current assets - derivative instruments $ 350,351 $ 58,246 $ — $ (446 ) $ 408,151 Other long-term assets - derivative instruments 296,441 29,649 210 (6,740 ) 319,560 Total assets 646,792 87,895 210 (7,186 ) 727,711 Liabilities Current liabilities - derivative instruments (214 ) (563 ) (5,126 ) 446 (5,457 ) Long-term liabilities - derivative instruments (1,520 ) (5,220 ) (2,269 ) 6,740 (2,269 ) Total liabilities (1,734 ) (5,783 ) (7,395 ) 7,186 (7,726 ) Net assets (liabilities) $ 645,058 $ 82,112 $ (7,185 ) $ — $ 719,985 (a) Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets. |
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: Thousands of dollars Oil Commodity Derivatives (a) Natural Gas Commodity Derivatives (a) Interest Rate Derivatives (b) Total Financial Instruments Three Months Ended September 30, 2015 Net gain (loss) $ 234,158 $ 18,854 $ (996 ) $ 252,016 Three Months Ended September 30, 2014 Net gain $ 133,666 $ 12,505 $ — $ 146,171 Nine Months Ended September 30, 2015 Net gain (loss) $ 261,360 $ 35,412 $ (3,411 ) $ 293,361 Nine Months Ended September 30, 2014 Net loss $ (15,553 ) $ (5,504 ) $ — $ (21,057 ) (a) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. (b) Included in loss on interest rate swaps on the consolidated statements of operations. |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables set 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. 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 September 30, 2015 Assets (liabilities) Crude Oil Crude oil swaps $ — $ 548,524 $ — $ 548,524 Crude oil collars — — 33,477 33,477 Crude oil puts — — 16,835 16,835 Natural Gas Natural gas swaps — 55,075 — 55,075 Natural gas collars — — 4,490 4,490 Natural gas puts — — 9,639 9,639 Interest rate swaps Interest rate swaps — (6,212 ) — (6,212 ) Available-for-sale securities Equities 2,419 — — 2,419 Mutual funds 11,304 — — 11,304 Exchange traded funds 4,805 — — 4,805 Net assets $ 18,528 $ 597,387 $ 64,441 $ 680,356 Thousands of dollars Level 1 Level 2 Level 3 Total As of December 31, 2014 Assets (liabilities) Crude Oil Crude oil swaps $ — $ 583,648 $ — $ 583,648 Crude oil collars — — 44,405 44,405 Crude oil puts — — 17,005 17,005 Natural gas commodity derivatives 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 tables set forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: Three Months Ended September 30, 2015 2014 Thousands of dollars Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 41,001 $ 15,010 $ 1,540 $ 840 Derivative instrument settlements (b) 11,903 4,050 — 347 (Loss) gain (b)(c) (2,592 ) (4,931 ) 5,529 (222 ) Ending balance $ 50,312 $ 14,129 $ 7,069 $ 965 Nine Months Ended September 30, 2015 2014 Thousands of dollars Oil Natural Gas Oil Natural Gas Assets (a): Beginning balance $ 61,410 $ 19,892 $ 8,957 $ 1,848 Derivative instrument settlements (b) 31,454 11,854 — 389 Loss (b)(c) (42,552 ) (17,617 ) (1,888 ) (1,272 ) Ending balance $ 50,312 $ 14,129 $ 7,069 $ 965 (a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, purchases or issuances. (b) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. (c) Represents loss on mark-to-market of derivative instruments. |
Fair Value Inputs, Assets, Quantitative Information | For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2015 , the significant unobservable inputs used in the fair value measurements were as follows: Fair Value at Valuation Thousands of dollars September 30, 2015 Technique Unobservable Input Range Oil Options $ 50,312 Option Pricing Model Oil forward commodity prices $45.09/Bbl - $56.04/Bbl Oil volatility 27.94% - 44.82% Own credit risk 5% Natural Gas Options 14,129 Option Pricing Model Gas forward commodity prices $2.52/MMBtu - $3.29/MMBtu Gas volatility 22.58% - 58.91% Own credit risk 5% Total $ 64,441 For Level 3 derivative instruments 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 |
Other Assets Other Assets (Tabl
Other Assets Other Assets (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Other Assets [Abstract] | |
Schedule of Other Assets [Table Text Block] | As of September 30, 2015 , and December 31, 2014 , our other long-term assets were $119.7 million and $157.0 million , respectively, consisting of the following: As of Thousands of dollars September 30, 2015 December 31, 2014 Debt issuance costs $ 62,341 $ 52,787 Available-for-sale securities 18,528 19,345 Deposit for Jay Field net profit interest obligation 18,263 18,263 Property reclamation deposit 10,735 10,735 CO 2 supply advances and deposits — 50,792 Other 9,848 5,120 Total $ 119,715 $ 157,042 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments | Our long-term debt is detailed in the following table: As of Thousands of dollars September 30, 2015 December 31, 2014 Credit facility $ 1,253,000 $ 2,194,500 Promissory note 3,000 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 (16,534 ) 1,560 Total debt 3,044,466 3,352,160 Less: current portion of long-term debt (603 ) (105,000 ) Total long-term debt $ 3,043,863 $ 3,247,160 |
Schedule of Interest Expense | Interest Expense Our interest expense is detailed as follows: Three Months Ended Nine Months Ended September 30, September 30, Thousands of dollars 2015 2014 2015 2014 Credit agreement (including commitment fees) $ 8,828 $ 4,539 $ 32,422 $ 14,886 Senior Unsecured Notes 23,311 23,311 69,933 69,933 Senior Secured Notes 15,031 — 28,893 — Amortization of net discount/premium and deferred issuance costs (a) 3,816 1,765 20,885 5,779 Capitalized interest (67 ) (121 ) (145 ) (238 ) Total $ 50,919 $ 29,494 $ 151,988 $ 90,360 (a) The three months and nine months ended September 30, 2015 include a write-off of zero and $10.6 million , respectively, of debt issuance costs relating to the reduction of our credit facility borrowing base. |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Changes in ARO for the period ended September 30, 2015 , and the year ended December 31, 2014 are presented in the following table: Nine Months Ended Year Ended Thousands of dollars September 30, 2015 December 31, 2014 Carrying amount, beginning of period $ 238,411 $ 123,769 Acquisitions 796 95,800 Divested properties (261 ) — Liabilities incurred 2,140 4,020 Liabilities settled (6,679 ) (1,708 ) Revisions 2,703 6,770 Accretion expense 12,597 9,760 Carrying amount, end of period 249,707 238,411 Less: current portion of ARO (2,390 ) (4,948 ) Non-current portion of ARO $ 247,317 $ 233,463 |
Pension and Postretirement Be29
Pension and Postretirement Benefits Pension and Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Pensions and Postretirement Benefits [Abstract] | |
Schedule of Net Benefit Costs | The components of net periodic benefit costs reflected in our consolidated statements of operations for the three months and nine months ended September 30, 2015 consist of the following: Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Thousands of dollars Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Service cost $ 68 $ 8 $ 203 $ 25 Interest cost 254 39 761 117 Expected return on plan assets (336 ) (24 ) (1,007 ) (74 ) Net periodic (income) benefit costs $ (14 ) $ 23 $ (43 ) $ 68 |
Partners' Equity (Tables)
Partners' Equity (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Partners' Capital [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | The following is a reconciliation of net loss and weighted average units for calculating basic net loss per common unit and diluted net loss per common unit. Three Months Ended Nine Months Ended September 30, September 30, Thousands, except per unit amounts 2015 2014 2015 2014 Net (loss) income attributable to the partnership $ (1,327,929 ) $ 130,643 $ (1,692,461 ) $ 16,160 Less: Net (loss) income attributable to participating units (31,662 ) 1,868 (40,612 ) 40 Distributions to Series A preferred unitholders 4,125 4,125 12,375 5,958 Non-cash distributions to Series B preferred unitholders 7,145 — 13,553 — Net (loss) income attributable to Common Unitholders $ (1,307,537 ) $ 124,650 $ (1,677,777 ) $ 10,162 Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands): Common Units 211,766 120,473 211,369 119,806 Dilutive units (a) — 777 — 738 Denominator for diluted net (loss) income per unit 211,766 121,250 211,369 120,544 Net (loss) income per common unit Basic $ (6.17 ) $ 1.03 $ (7.94 ) $ 0.08 Diluted $ (6.17 ) $ 1.03 $ (7.94 ) $ 0.08 (a) The three months and nine months ended September 30, 2015 exclude 749 and 724 , respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. |
Accumulated Other Comprehensi31
Accumulated Other Comprehensive Loss (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Changes in accumulated other comprehensive loss by component, net of tax, for the three months and nine months ended September 30, 2015 were as follows: Three Months Ended September 30, 2015 Gain (loss) on Thousands of dollars Available-For-Sale Securities Postretirement Benefits Total Accumulated comprehensive loss attributable to the partnership as of June 30, 2015 $ (53 ) $ (280 ) $ (333 ) Other comprehensive loss before reclassification (637 ) — (637 ) Amounts reclassified from accumulated other comprehensive loss (a) — — — Net current period other comprehensive loss (637 ) — (637 ) Less: noncontrolling interest (394 ) — (394 ) Accumulated comprehensive loss attributable to the partnership as of September 30, 2015 $ (296 ) $ (280 ) $ (576 ) Nine Months Ended September 30, 2015 Gain (loss) on Thousands of dollars Available-For-Sale Securities Postretirement Benefits Total Accumulated comprehensive loss attributable to the partnership as of December 31, 2014 $ (112 ) $ (280 ) $ (392 ) Other comprehensive loss before reclassification (390 ) — (390 ) Amounts reclassified from accumulated other comprehensive loss (a) (147 ) — (147 ) Net current period other comprehensive income (537 ) — (537 ) Less: noncontrolling interest (353 ) — (353 ) Accumulated comprehensive loss attributable to the partnership as of September 30, 2015 $ (296 ) $ (280 ) $ (576 ) (a) Amounts were reclassified from accumulated other comprehensive loss to other expense (income), net on the consolidated statements of operations. |
Restructuring Costs (Tables)
Restructuring Costs (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Restructuring Costs [Abstract] | |
Restructuring and Related Costs | Three Months Ended Nine Months Ended Thousands of dollars September 30, 2015 September 30, 2015 Severance payments — 4,768 Unit-based compensation expense (191 ) 1,343 Other termination costs (87 ) 302 Total (278 ) 6,413 |
Acquisitions Narrative (Details
Acquisitions Narrative (Details) - USD ($) $ in Thousands, shares in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2015 | Aug. 31, 2015 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Nov. 19, 2014 | Oct. 24, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | |||||||||||
Non-oil and gas assets | $ 4,888,120 | $ 4,888,120 | $ 6,454,201 | ||||||||
Intangibles, net | 1,538 | 1,538 | 8,336 | ||||||||
Long-term asset retirement obligation | 247,317 | 247,317 | 233,463 | ||||||||
Asset retirement obligation | 249,707 | 249,707 | 238,411 | $ 123,769 | |||||||
Weld County, Colorado [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash consideration from exchange of assets | 4,800 | ||||||||||
Gain on transaction | 7,500 | ||||||||||
CO2 Assets [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assets acquired net of liabilities assumed | $ 70,200 | ||||||||||
Payments to acquire businesses, net of cash acquired | 0 | $ 200 | $ 14,300 | $ 49,900 | |||||||
Non-oil and gas assets | 70,500 | 70,500 | |||||||||
Intangibles, net | 5,100 | 5,100 | |||||||||
Long-term asset retirement obligation | $ 300 | $ 300 | |||||||||
QRE [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assets acquired net of liabilities assumed | $ 1,408,434 | ||||||||||
Non-oil and gas assets | 17,866 | ||||||||||
Long-term asset retirement obligation | $ 91,465 | ||||||||||
Property ownership interest | 100.00% | ||||||||||
Ownership percentage | 59.00% | ||||||||||
Stock issued during period for acquisition | 71.5 | ||||||||||
Antares [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assets acquired net of liabilities assumed | $ 122,300 | $ 50,000 | |||||||||
Stock issued during period for acquisition | 4.3 | ||||||||||
Asset retirement obligation | $ 1,700 | ||||||||||
Kingfisher County, Oklahoma [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash consideration from exchange of assets | $ 3,200 | ||||||||||
Property ownership interest | 0.00% | 0.00% | |||||||||
Common Class C [Member] | QRE [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash paid to acquiree unitholders | $ 350,000 | ||||||||||
Unproved [Member] | Antares [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assets acquired net of liabilities assumed | 110,900 | ||||||||||
Proved [Member] | Antares [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assets acquired net of liabilities assumed | $ 13,100 |
Acquisitions Purchase Price All
Acquisitions Purchase Price Allocation (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | May. 31, 2015 | Nov. 19, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | ||||||||||
Impairment of goodwill | $ 0 | $ 0 | $ 95,947 | $ 0 | ||||||
Cash | 12,091 | $ 3,227 | 12,091 | $ 3,227 | $ 12,628 | $ 2,458 | ||||
Current derivative instrument assets | 400,857 | 400,857 | 408,151 | |||||||
Non-oil and gas assets | 4,888,120 | 4,888,120 | 6,454,201 | |||||||
Goodwill | 0 | $ 95,900 | 0 | 92,024 | ||||||
Long-term derivative instrument assets | 267,681 | 267,681 | 319,560 | |||||||
Other long-term assets | 119,715 | 119,715 | 157,042 | |||||||
Current derivative instrument liabilities | 5,289 | 5,289 | 5,457 | |||||||
Current asset retirement obligation | 2,390 | 2,390 | 4,948 | |||||||
Credit facility debt | 1,253,000 | 1,253,000 | 2,194,500 | |||||||
Senior notes at fair value | 650,000 | 650,000 | 0 | |||||||
Long-term asset retirement obligation | 247,317 | 247,317 | 233,463 | |||||||
Other long-term liabilities | 24,615 | 24,615 | 25,135 | |||||||
Ark-La-Tex [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets acquired net of liabilities assumed | $ 3,000 | |||||||||
CO2 Assets [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Payments to Acquire Businesses, Net of Cash Acquired | 0 | $ 200 | 14,300 | $ 49,900 | ||||||
Non-oil and gas assets | 70,500 | 70,500 | ||||||||
Long-term asset retirement obligation | $ 300 | $ 300 | ||||||||
Assets acquired net of liabilities assumed | $ 70,200 | |||||||||
QRE [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 | |||||||||
Noncontrolling interest | 7,173 | |||||||||
Assets acquired net of liabilities assumed | $ 1,408,434 |
Acquisitions Pro Forma Informat
Acquisitions Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2014 | Sep. 30, 2014 | |
Business Combinations [Abstract] | ||
Revenues | $ 564,321 | $ 1,009,362 |
Net income attributable to the partnership | $ 211,356 | $ 45,286 |
Basic (usd per share) | $ 1 | $ 0.19 |
Diluted (usd per share) | $ 0.99 | $ 0.19 |
Financial Instruments and Fair
Financial Instruments and Fair Value Measurements - Oil and Natural Gas Contracts (Details) | Sep. 30, 2015Energy / DaysDays / bbl$ / Energy$ / bbl | |
Deferred Premium [Member] | Put Option [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 420 | |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.64 | |
Deferred Premium [Member] | Put Option [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 11,350 | |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.66 | |
Deferred Premium [Member] | Put Option [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 10,445 | |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.69 | |
Oil | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 26,368 | |
Derivative, Swap Type, Average Fixed Price | 93.46 | |
Oil | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 22,804 | |
Derivative, Swap Type, Average Fixed Price | 89.01 | |
Oil | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 13,817 | |
Derivative, Swap Type, Average Fixed Price | 85.32 | |
Oil | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 493 | |
Derivative, Swap Type, Average Fixed Price | 82.20 | |
Oil | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 | |
Natural Gas | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 92,311 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.76 | |
Natural Gas | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 77,030 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.08 | |
Natural Gas | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 54,056 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.02 | |
Natural Gas | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 15,870 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.26 | |
Natural Gas | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 8,000 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.20 | |
NYMEX WTI [Member] | Oil | Swap [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 20,043 | |
Derivative, Swap Type, Average Fixed Price | 93.27 | |
NYMEX WTI [Member] | Oil | Swap [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 15,504 | |
Derivative, Swap Type, Average Fixed Price | 88.07 | |
NYMEX WTI [Member] | Oil | Swap [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 13,519 | |
Derivative, Swap Type, Average Fixed Price | 85.05 | |
NYMEX WTI [Member] | Oil | Swap [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 493 | |
Derivative, Swap Type, Average Fixed Price | 82.20 | |
NYMEX WTI [Member] | Oil | Swap [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 | |
NYMEX WTI [Member] | Oil | Collars [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 2,025 | |
Derivative, Average floor price | 90 | |
Derivative, Average ceiling price | 111.73 | |
NYMEX WTI [Member] | Oil | Collars [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 1,500 | |
Derivative, Average floor price | 80 | |
Derivative, Average ceiling price | 102 | |
NYMEX WTI [Member] | Oil | Collars [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
NYMEX WTI [Member] | Oil | Collars [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
NYMEX WTI [Member] | Oil | Collars [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
NYMEX WTI [Member] | Oil | Put Option [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 500 | |
Derivative, Average Price Risk Option Strike Price | 90 | |
NYMEX WTI [Member] | Oil | Put Option [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 1,000 | |
Derivative, Average Price Risk Option Strike Price | 90 | |
NYMEX WTI [Member] | Oil | Put Option [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average Price Risk Option Strike Price | 0 | |
NYMEX WTI [Member] | Oil | Put Option [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average Price Risk Option Strike Price | 0 | |
NYMEX WTI [Member] | Oil | Put Option [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average Price Risk Option Strike Price | 0 | |
IPE Brent [Member] | Oil | Swap [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 3,300 | |
Derivative, Swap Type, Average Fixed Price | 97.73 | |
IPE Brent [Member] | Oil | Swap [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 4,300 | |
Derivative, Swap Type, Average Fixed Price | 95.17 | |
IPE Brent [Member] | Oil | Swap [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 298 | |
Derivative, Swap Type, Average Fixed Price | 97.50 | |
IPE Brent [Member] | Oil | Swap [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 | |
IPE Brent [Member] | Oil | Swap [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 | |
IPE Brent [Member] | Oil | Collars [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 500 | |
Derivative, Average floor price | 90 | |
Derivative, Average ceiling price | 109.50 | |
IPE Brent [Member] | Oil | Collars [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 500 | |
Derivative, Average floor price | 90 | |
Derivative, Average ceiling price | 101.25 | |
IPE Brent [Member] | Oil | Collars [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
IPE Brent [Member] | Oil | Collars [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
IPE Brent [Member] | Oil | Collars [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | |
Derivative, Average floor price | 0 | |
Derivative, Average ceiling price | 0 | |
Mich Con City-Gate [Member] | Natural Gas | Swap [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 17,500 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.26 | |
Mich Con City-Gate [Member] | Natural Gas | Swap [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 29,000 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.91 | |
Mich Con City-Gate [Member] | Natural Gas | Swap [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 24,000 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.71 | |
Mich Con City-Gate [Member] | Natural Gas | Swap [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 14,000 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.15 | |
Mich Con City-Gate [Member] | Natural Gas | Swap [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 8,000 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.20 | |
Henry Hub [Member] | Natural Gas | Swap [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 54,891 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.84 | |
Henry Hub [Member] | Natural Gas | Swap [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 36,050 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.24 | |
Henry Hub [Member] | Natural Gas | Swap [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 19,016 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.43 | |
Henry Hub [Member] | Natural Gas | Swap [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 1,870 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.15 | |
Henry Hub [Member] | Natural Gas | Swap [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 | |
Derivative, Swap Type, Average Fixed Price | $ / Energy | 0 | |
Henry Hub [Member] | Natural Gas | Collars [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 18,000 | |
Derivative, Average floor price | $ / Energy | 5 | |
Derivative, Average ceiling price | $ / Energy | 7.48 | |
Henry Hub [Member] | Natural Gas | Collars [Member] | Term of Calendar 2016 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 630 | |
Derivative, Average floor price | $ / Energy | 4 | |
Derivative, Average ceiling price | $ / Energy | 5.55 | |
Henry Hub [Member] | Natural Gas | Collars [Member] | Term of Calendar 2017 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 595 | |
Derivative, Average floor price | $ / Energy | 4 | |
Derivative, Average ceiling price | $ / Energy | 6.15 | |
Henry Hub [Member] | Natural Gas | Collars [Member] | Term of Calendar 2018 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 | |
Derivative, Average floor price | $ / Energy | 0 | |
Derivative, Average ceiling price | $ / Energy | 0 | |
Henry Hub [Member] | Natural Gas | Collars [Member] | Term of Calendar 2019 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 0 | |
Derivative, Average floor price | $ / Energy | 0 | |
Derivative, Average ceiling price | $ / Energy | 0 | |
Henry Hub [Member] | Natural Gas | Put Option [Member] | Term of Calendar 2015 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | Energy / Days | 1,920 | |
Derivative, Average Price Risk Option Strike Price | $ / Energy | 4.78 | |
Derivative, Average Deferred Premium Per Unit | $ / Energy | 0.64 | [1] |
Henry Hub [Member] | Natural Gas | 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 | |
Henry Hub [Member] | Natural Gas | 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 | |
Henry Hub [Member] | Natural Gas | 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 | |
Henry Hub [Member] | Natural Gas | 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 | |
[1] | (a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume. |
Financial Instruments Financial
Financial Instruments Financial Intruments and Fair Value Measurements - Prepaid Derivative Premiums (Details) $ in Thousands | Sep. 30, 2015USD ($) |
Oil | Term of Calendar 2015 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | $ 1,180 |
Oil | Term of Calendar 2016 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | 7,438 |
Oil | Term of Calendar 2017 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | 734 |
Natural Gas | Term of Calendar 2015 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | 501 |
Natural Gas | Term of Calendar 2016 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | 952 |
Natural Gas | Term of Calendar 2017 [Member] | |
Prepaid Derivative Premiums [Line Items] | |
Prepaid Derivative Premium | $ 0 |
Financial Instruments Financi38
Financial Instruments Financial Instruments - Interest Rate Swaps (Details) $ in Thousands | Sep. 30, 2015USD ($) |
Term of Calendar 2015 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 374,031 |
Derivative, Fixed Interest Rate | 1.64% |
Term of Calendar 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Notional Amount | $ 410,000 |
Derivative, Fixed Interest Rate | 1.72% |
Financial Instruments and Fai39
Financial Instruments and Fair Value Measurements - Not Designated As Hedging Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | $ 400,857 | $ 408,151 | |
Long-term derivative instrument assets | 267,681 | 319,560 | |
Current liabilities - derivative instruments | (5,289) | (5,457) | |
Long-term liabilities - derivative instruments | (1,421) | (2,269) | |
Not Designated as Hedging Instrument [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | 400,857 | 408,151 | |
Long-term derivative instrument assets | 267,681 | 319,560 | |
Total assets | 668,538 | 727,711 | |
Current liabilities - derivative instruments | (5,289) | (5,457) | |
Long-term liabilities - derivative instruments | (1,421) | (2,269) | |
Total liabilities | (6,710) | (7,726) | |
Net assets (liabilities) | 661,828 | 719,985 | |
Oil Commodity Derivatives | Not Designated as Hedging Instrument [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | 358,741 | 350,351 | |
Long-term derivative instrument assets | 240,177 | 296,441 | |
Total assets | 598,918 | 646,792 | |
Current liabilities - derivative instruments | (40) | (214) | |
Long-term liabilities - derivative instruments | (43) | (1,520) | |
Total liabilities | (83) | (1,734) | |
Net assets (liabilities) | 598,835 | 645,058 | |
Natural Gas Commodity Derivatives | Not Designated as Hedging Instrument [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | 44,281 | 58,246 | |
Long-term derivative instrument assets | 30,886 | 29,649 | |
Total assets | 75,167 | 87,895 | |
Current liabilities - derivative instruments | (2,214) | (563) | |
Long-term liabilities - derivative instruments | (3,748) | (5,220) | |
Total liabilities | (5,962) | (5,783) | |
Net assets (liabilities) | 69,205 | 82,112 | |
Interest Rate Derivatives | Not Designated as Hedging Instrument [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | 0 | 0 | |
Long-term derivative instrument assets | 0 | 210 | |
Total assets | 0 | 210 | |
Current liabilities - derivative instruments | (5,200) | (5,126) | |
Long-term liabilities - derivative instruments | (1,012) | (2,269) | |
Total liabilities | (6,212) | (7,395) | |
Net assets (liabilities) | (6,212) | (7,185) | |
Commodity Derivatives Netting | Not Designated as Hedging Instrument [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current assets - derivative instruments | [1] | (2,165) | (446) |
Long-term derivative instrument assets | [1] | (3,382) | (6,740) |
Total assets | [1] | (5,547) | (7,186) |
Current liabilities - derivative instruments | [1] | 2,165 | 446 |
Long-term liabilities - derivative instruments | [1] | 3,382 | 6,740 |
Total liabilities | [1] | 5,547 | 7,186 |
Net assets (liabilities) | [1] | $ 0 | $ 0 |
[1] | Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets. |
Financial Instruments and Fai40
Financial Instruments and Fair Value Measurements - Gains and Losses on Derivative Instruments Not Designated As Hedging Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (gain) on derivative instruments | $ 253,012 | $ 146,171 | $ 296,772 | $ (21,057) | |
Not Designated as Hedging Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (gain) on derivative instruments | 252,016 | 146,171 | 293,361 | (21,057) | |
Oil | Not Designated as Hedging Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (gain) on derivative instruments | [1] | 234,158 | 133,666 | 261,360 | (15,553) |
Natural Gas | Not Designated as Hedging Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (gain) on derivative instruments | [1] | 18,854 | 12,505 | 35,412 | (5,504) |
Interest Rate Swap | Not Designated as Hedging Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (gain) on derivative instruments | [2] | $ (996) | $ 0 | $ (3,411) | $ 0 |
[1] | Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. | ||||
[2] | Included in loss on interest rate swaps on the consolidated statements of operations. |
Financial Instruments and Fai41
Financial Instruments and Fair Value Measurements - Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value, Net Asset (Liability) | $ 680,356 | $ 739,330 |
Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value, Net Asset (Liability) | 18,528 | 19,345 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value, Net Asset (Liability) | 597,387 | 638,683 |
Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value, Net Asset (Liability) | 64,441 | 81,302 |
Swap [Member] | Oil | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 548,524 | 583,648 |
Swap [Member] | Oil | 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] | Oil | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 548,524 | 583,648 |
Swap [Member] | Oil | 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] | Natural Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 55,075 | 62,220 |
Swap [Member] | Natural Gas | 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 | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 55,075 | 62,220 |
Swap [Member] | Natural Gas | 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 | (6,212) | (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 | (6,212) | (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 |
Collars [Member] | Oil | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 33,477 | 44,405 |
Collars [Member] | Oil | 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] | Oil | 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] | Oil | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 33,477 | 44,405 |
Collars [Member] | Natural Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 4,490 | 13,256 |
Collars [Member] | Natural Gas | 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 | 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 | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 4,490 | 13,256 |
Put Option [Member] | Oil | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 16,835 | 17,005 |
Put Option [Member] | Oil | 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] | Oil | 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] | Oil | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 16,835 | 17,005 |
Put Option [Member] | Natural Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 9,639 | 6,636 |
Put Option [Member] | Natural Gas | 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 | 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 | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 9,639 | 6,636 |
Equities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 2,419 | 4,138 |
Equities | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 2,419 | 4,138 |
Equities | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 0 | 0 |
Equities | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 0 | 0 |
Mutual funds | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 11,304 | 10,577 |
Mutual funds | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 11,304 | 10,577 |
Mutual funds | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 0 | 0 |
Mutual funds | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 0 | 0 |
Exchange traded funds | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 4,805 | 4,630 |
Exchange traded funds | Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 4,805 | 4,630 |
Exchange traded funds | Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 0 | 0 |
Exchange traded funds | Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | $ 0 | $ 0 |
Financial Instruments and Fai42
Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Fair Value, Net Derivative Asset (Liability) [Roll Forward] | |||||
Derivative instrument settlements | $ (351,518) | $ 34,228 | |||
(Loss) gain | 293,361 | (21,057) | |||
Oil | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | |||||
Fair Value, Net Derivative Asset (Liability) [Roll Forward] | |||||
Beginning balance | [1] | $ 41,001 | $ 1,540 | 61,410 | 8,957 |
Derivative instrument settlements | [1],[2] | 11,903 | 0 | 31,454 | 0 |
(Loss) gain | [1],[2],[3] | (2,592) | 5,529 | (42,552) | (1,888) |
Ending balance | [1] | 50,312 | 7,069 | 50,312 | 7,069 |
Natural Gas | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | |||||
Fair Value, Net Derivative Asset (Liability) [Roll Forward] | |||||
Beginning balance | [1] | 15,010 | 840 | 19,892 | 1,848 |
Derivative instrument settlements | [1],[2] | 4,050 | 347 | 11,854 | 389 |
(Loss) gain | [1],[2],[3] | (4,931) | (222) | (17,617) | (1,272) |
Ending balance | [1] | $ 14,129 | $ 965 | $ 14,129 | $ 965 |
[1] | We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, purchases or issuances. | ||||
[2] | Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations. | ||||
[3] | Represents loss on mark-to-market of derivative instruments. |
Financial Instruments Financi43
Financial Instruments Financial Instruments and Fair Value Measurements - Significant Unobservable Inputs Used in the Fair Value Measurements (Details) - Option Pricing Model Valuation Technique [Member] - Level 3 [Member] - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 64,441 | |
Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 81,302 | |
Fair Value Inputs, Counterparty Credit Risk | 5.00% | 5.00% |
Oil | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 50,312 | |
Oil | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 61,410 | |
Oil | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs, Offered Quotes | $ 56.04 | $ 71.66 |
Fair Value Assumptions, Expected Volatility Rate | 44.82% | 46.16% |
Oil | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs, Offered Quotes | $ 45.09 | $ 53.27 |
Fair Value Assumptions, Expected Volatility Rate | 27.94% | 29.21% |
Natural Gas | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 14,129 | |
Natural Gas | Derivative Financial Instruments, Assets [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Assets, Fair Value Disclosure | $ 19,892 | |
Natural Gas | Derivative Financial Instruments, Assets [Member] | Maximum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs, Offered Quotes | $ 3.29 | $ 3.99 |
Fair Value Assumptions, Expected Volatility Rate | 58.91% | 63.51% |
Natural Gas | Derivative Financial Instruments, Assets [Member] | Minimum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs, Offered Quotes | $ 2.52 | $ 2.88 |
Fair Value Assumptions, Expected Volatility Rate | 22.58% | 18.59% |
Financial Instruments and Fai44
Financial Instruments and Fair Value Measurements - Narrative (Details) - Credit Concentration Risk [Member] | 9 Months Ended |
Sep. 30, 2015 | |
Well Fargo Bank [Member] | |
Derivative [Line Items] | |
Concentration risk | 19.00% |
Credit Suisse [Member] | |
Derivative [Line Items] | |
Concentration risk | 11.00% |
JP Morgan Chase Bank [Member] | |
Derivative [Line Items] | |
Concentration risk | 11.00% |
Barclays Bank PLC [Member] | |
Derivative [Line Items] | |
Concentration risk | 11.00% |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||||
General and administrative expenses | $ 23,276,000 | $ 18,737,000 | $ 78,400,000 | $ 53,886,000 | |
PCEC [Member] | |||||
Related Party Transaction [Line Items] | |||||
Monthly Fee for Indirect Costs | 700,000 | 700,000 | 700,000 | 700,000 | |
Current receivables | 1,600,000 | 1,600,000 | $ 2,400,000 | ||
Indirect expenses | 2,100,000 | 2,100,000 | 6,300,000 | 6,300,000 | |
General and administrative expenses | 2,300,000 | $ 3,800,000 | 7,300,000 | $ 8,900,000 | |
Other Affiliates [Member] | |||||
Related Party Transaction [Line Items] | |||||
Current receivables | $ 500,000 | 500,000 | $ 100,000 | ||
Senior Secured Notes [Member] | EIG [Member] | |||||
Related Party Transaction [Line Items] | |||||
Transaction fee (related party) | 13,000,000 | ||||
Series B [Member] | EIG [Member] | |||||
Related Party Transaction [Line Items] | |||||
Transaction fee (related party) | $ 7,000,000 |
Impairments (Details)
Impairments (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Mar. 31, 2015 | Dec. 31, 2014 | |
Reserve Quantities [Line Items] | ||||||
Percentage rate of escalation, impairment of assets | 2.00% | |||||
Discount rate, future net revenues for estimated proved reserves | 10.00% | |||||
Impairment of oil and natural gas properties | $ 1,440,167 | $ 29,434 | $ 1,499,280 | $ 29,434 | ||
Goodwill | 0 | 0 | $ 95,900 | $ 92,024 | ||
Impairment of goodwill | 0 | 0 | 95,947 | $ 0 | ||
Permian Basin [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 49,700 | 82,800 | ||||
Rockies [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 17,400 | 3,000 | 34,100 | |||
MidContinent [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 12,200 | 21,500 | ||||
FLORIDA | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 420,200 | 19,900 | 420,200 | |||
Ark-La-Tex [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 262,100 | 262,100 | ||||
California [Member] [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | 73,100 | 73,100 | ||||
MICHIGAN | ||||||
Reserve Quantities [Line Items] | ||||||
Impairment of oil and natural gas properties | $ 605,400 | $ 6,500 | $ 605,400 |
Other Assets (Details)
Other Assets (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2015 | Apr. 08, 2015 | Dec. 31, 2014 | |
Unamortized debt issuance expense | $ 62,341,000 | $ 62,341,000 | $ 52,787,000 | |
Noncurrent equity securities | 18,528,000 | 18,528,000 | 19,345,000 | |
Retainage Deposit | 0 | 0 | 50,792,000 | |
Other assets, miscellaneous | 9,848,000 | 9,848,000 | 5,120,000 | |
Other long-term assets | 119,715,000 | 119,715,000 | 157,042,000 | |
Current borrowing capacity | 1,800,000,000 | 1,800,000,000 | $ 1,800,000,000 | 2,500,000,000 |
Write off of deferred debt issuance cost | 0 | 10,600,000 | ||
Maximum borrowing capacity | 5,000,000,000 | 5,000,000,000 | ||
Deposit for Jay Field net profit interest obligation | ||||
Noncurrent deposit assets | 18,263,000 | 18,263,000 | 18,263,000 | |
Property reclamation deposit | ||||
Noncurrent deposit assets | 10,735,000 | 10,735,000 | 10,735,000 | |
Senior Secured Notes [Member] | ||||
Unamortized debt issuance expense | $ 21,600,000 | $ 21,600,000 | $ 0 |
Long-Term Debt Total long term
Long-Term Debt Total long term debt (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Credit facility | $ 1,253,000 | $ 2,194,500 |
Notes Payable | 3,000 | 1,100 |
Senior notes at fair value | 650,000 | 0 |
Net (discount) premium on Senior Notes | 16,534 | (1,560) |
Total debt | 3,044,466 | 3,352,160 |
Long-term Debt, Current Maturities | (603) | (105,000) |
Long-term Debt | 3,043,863 | 3,247,160 |
Senior Notes One [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | 305,000 | 305,000 |
Net premium on Senior Notes | 3,100 | |
Senior Notes Two [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 850,000 | $ 850,000 |
Long-Term Debt - Credit Facilit
Long-Term Debt - Credit Facility (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2015 | Apr. 08, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||||
Current borrowing capacity | $ 1,800,000,000 | $ 1,800,000,000 | $ 1,800,000,000 | $ 2,500,000,000 |
Credit facility | 1,253,000,000 | 1,253,000,000 | 2,089,500,000 | |
Liquidity percent of borrowing base | 10.00% | |||
Maximum borrowing capacity | 5,000,000,000 | 5,000,000,000 | ||
Credit facility | 1,253,000,000 | 1,253,000,000 | 2,194,500,000 | |
Unamortized debt issuance expense | 62,341,000 | 62,341,000 | 52,787,000 | |
Write off of deferred debt issuance cost | 0 | 10,600,000 | ||
London Interbank Offered Rate (LIBOR) [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | $ 1,300,000,000 | $ 1,300,000,000 | ||
Interest rate, stated percentage | 2.4511% | 2.4511% | ||
Prime Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | $ 5,000,000 | $ 5,000,000 | ||
Interest rate, stated percentage | 4.50% | 4.50% | ||
Senior Secured Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, face amount | $ 650,000,000 | |||
Interest rate, stated percentage | 9.25% | |||
Unamortized debt issuance expense | $ 21,600,000 | $ 21,600,000 | 0 | |
Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Unamortized debt issuance expense | $ 23,600,000 | $ 23,600,000 | $ 33,500,000 | |
Common Units [Member] | ||||
Debt Instrument [Line Items] | ||||
Liquidity percent of borrowing base | 10.00% | |||
Preferred Units B [Member] | ||||
Debt Instrument [Line Items] | ||||
Liquidity percent of borrowing base | 5.00% | |||
Libor Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
base rate and LIBOR margin increase | 0.25% |
Long-Term Debt - Senior Notes (
Long-Term Debt - Senior Notes (Details) - USD ($) | 3 Months Ended | ||
Sep. 30, 2015 | Apr. 08, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Senior notes at fair value | $ 650,000,000 | $ 0 | |
Senior notes, net | 1,788,466,000 | 1,156,560,000 | |
Unamortized debt issuance expense | 62,341,000 | 52,787,000 | |
Senior Secured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes at fair value | $ 650,000,000 | ||
Interest rate, stated percentage | 9.25% | ||
Discount or premium percentage | 97.00% | ||
Proceeds from (payments for) other financing activities | 606,900,000 | ||
Debt instrument, face amount | $ 650,000,000 | ||
Senior notes, net | 631,900,000 | ||
Debt Instrument, Unamortized Discount | 18,100,000 | ||
Unamortized debt issuance expense | 21,600,000 | 0 | |
Fair value disclosure | $ 612,000,000 | ||
Senior Notes One [Member] | |||
Debt Instrument [Line Items] | |||
Interest rate, stated percentage | 8.625% | ||
Debt instrument, face amount | $ 305,000,000 | 305,000,000 | |
Senior notes, net | 301,900,000 | ||
Debt Instrument, Unamortized Discount | 3,100,000 | ||
Fair value disclosure | $ 138,000,000 | ||
Senior Notes Two [Member] | |||
Debt Instrument [Line Items] | |||
Interest rate, stated percentage | 7.875% | ||
Debt instrument, face amount | $ 850,000,000 | 850,000,000 | |
Senior notes, net | 854,600,000 | ||
Unamortized premium | (4,600,000) | ||
Fair value disclosure | 302,000,000 | ||
Unsecured Debt [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized debt issuance expense | $ 17,100,000 | $ 19,300,000 |
Long-Term Debt - Interest Expen
Long-Term Debt - Interest Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |||
Debt Instrument [Line Items] | ||||||
Amortization of net discount/premium and deferred issuance costs | $ 3,816 | [1] | $ 1,765 | $ 20,885 | [1] | $ 5,779 |
Capitalized interest | (67) | (121) | (145) | (238) | ||
Interest expense, net of capitalized interest | 50,919 | 29,494 | 151,988 | 90,360 | ||
Write off of deferred debt issuance cost | 0 | 10,600 | ||||
Line of Credit [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest expense | 8,828 | 4,539 | 32,422 | 14,886 | ||
Unsecured Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest expense | 23,311 | 23,311 | 69,933 | 69,933 | ||
Senior Secured Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest expense | $ 15,031 | $ 0 | $ 28,893 | $ 0 | ||
[1] | (a) The three months and nine months ended September 30, 2015 include a write-off of zero and $10.6 million, respectively, of debt issuance costs relating to the reduction of our credit facility borrowing base. |
Long-Term Debt Senior Secured N
Long-Term Debt Senior Secured Notes (Details) - USD ($) | 3 Months Ended | ||
Sep. 30, 2015 | Apr. 08, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Unamortized debt issuance expense | $ 62,341,000 | $ 52,787,000 | |
Senior notes at fair value | 650,000,000 | 0 | |
Subordinated Long-term Debt, Noncurrent | 1,788,466,000 | 1,156,560,000 | |
Senior Secured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized debt issuance expense | 21,600,000 | $ 0 | |
Senior notes at fair value | $ 650,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | ||
Discount or premium percentage | 97.00% | ||
Proceeds from (payments for) other financing activities | 606,900,000 | ||
Subordinated Long-term Debt, Noncurrent | 631,900,000 | ||
Debt Instrument, Unamortized Discount | $ 18,100,000 |
Condensed Consolidating Finan53
Condensed Consolidating Financial Statements Condenced Financial Information (Details) | Sep. 30, 2015 |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Number of subsidiaries not guaranteeing the Senior Notes | 2 |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Carrying amount, beginning of period | $ 238,411 | $ 123,769 |
Acquisitions | 796 | 95,800 |
Divested properties | (261) | 0 |
Liabilities incurred | 2,140 | 4,020 |
Liabilities settled | (6,679) | (1,708) |
Revisions | 2,703 | 6,770 |
Accretion expense | 12,597 | 9,760 |
Carrying amount, end of period | 249,707 | 238,411 |
Less: current portion of ARO | (2,390) | (4,948) |
Long-term asset retirement obligation | $ 247,317 | $ 233,463 |
Wells and Related Equipment and Facilities [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Credit adjusted risk free rate | 10.00% | |
Inflation adjustment rate | 2.00% | |
Maximum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Asset retirement obligations, assets, useful lives, minimum | 50 years | |
Minimum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Asset retirement obligations, assets, useful lives, minimum | 1 year |
Pension and Postretirement Be55
Pension and Postretirement Benefits Pension and Postretirement Benefits (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2015 | Sep. 30, 2015 | |
Pension Benefits | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Service cost | $ 68 | $ 203 |
Interest cost | 254 | 761 |
Expected return on plan assets | (336) | (1,007) |
Net periodic (income) benefit costs | (14) | (43) |
Postretirement Benefits | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Service cost | 8 | 25 |
Interest cost | 39 | 117 |
Expected return on plan assets | (24) | (74) |
Net periodic (income) benefit costs | $ 23 | $ 68 |
Commitments and Contingencies (
Commitments and Contingencies (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Commitments and Contingencies Disclosure [Abstract] | ||
Surety bonds, current carrying value | $ 26.4 | $ 21.1 |
Letters of credit outstanding, amount | $ 26.5 | $ 26.5 |
Partners' Equity (Details)
Partners' Equity (Details) - USD ($) | Apr. 08, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | May. 21, 2014 |
Capital Unit [Line Items] | |||||||||||
Series A preferred units, 8.0 million units issued and outstanding at each of September 30, 2015 and December 31, 2014 (note 12) | $ 193,215,000 | $ 193,215,000 | $ 193,215,000 | ||||||||
Preferred stock, dividend rate | 8.25% | ||||||||||
Preferred stock, par value | $ 25 | ||||||||||
Proceeds from Issuance of Preferred Stock and Preference Stock | 337,400,000 | ||||||||||
Non-cash distributions to Series B preferred unitholders | $ 7,145,000 | $ 0 | 13,553,000 | $ 0 | |||||||
Preferred units, issued | 8,000,000 | ||||||||||
Preferred units, offering costs | $ 6,800,000 | ||||||||||
Preferred Stock, Dividend Rate, Per-Dollar-Amount | $ 0.171875 | ||||||||||
Less: Distributions to Series A preferred unitholders | $ 4,125,000 | $ 4,125,000 | 12,375,000 | 5,958,000 | |||||||
Proceeds from Issuance of Common Stock | $ 200,000,000 | ||||||||||
Proceeds from issuance of common units, net | $ 4,768,000 | $ 25,917,000 | |||||||||
Common Units [Member] | |||||||||||
Capital Unit [Line Items] | |||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.1250 | $ 0.5025 | $ 0.4999 | $ 1.4925 | |||||||
Stock Issued During Period, Shares, Non Cash Stock Dividend | 163,314 | 0 | 284,898 | 0 | |||||||
Common units issued and outstanding (in units) | 211,800,000 | 211,800,000 | 210,900,000 | ||||||||
Common Units issued pursuant to vest grants (in shares) | 0 | 0 | 100,000 | 100,000 | |||||||
Long-term incentive compensation plans, number of shares eligible to be issued (in shares) | 5,900,000 | 5,900,000 | 1,800,000 | ||||||||
Distributions | $ 26,500,000 | $ 60,500,000 | $ 105,600,000 | $ 178,700,000 | |||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 749,000 | 724,000 | |||||||||
Equity Distribution Agreement [Member] | |||||||||||
Capital Unit [Line Items] | |||||||||||
Limited Partners' Capital Account, Units Issued | 0 | 543,845 | 0 | 269,774 | 976,611 | 25,300 | |||||
Proceeds from issuance of common units, net | $ 0 | $ 3,400,000 | $ 0 | $ 6,000,000 | $ 19,700,000 | $ 500,000 | |||||
Equivalent Units [Member] | |||||||||||
Capital Unit [Line Items] | |||||||||||
Cash equivalent to the distribution paid to unitholders | $ 600,000 | $ 900,000 | $ 2,700,000 | $ 2,800,000 | |||||||
Preferred Units B [Member] | |||||||||||
Capital Unit [Line Items] | |||||||||||
Series A preferred units, 8.0 million units issued and outstanding at each of September 30, 2015 and December 31, 2014 (note 12) | $ 350,000,000 | ||||||||||
Preferred stock, dividend rate | 8.00% | ||||||||||
Preferred stock, par value | $ 7.50 | ||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.02000 | $ 0.03489 | |||||||||
Stock Issued During Period, Shares, Non Cash Stock Dividend | 786,634 | 1,361,925 |
Partners' Equity - Earnings Per
Partners' Equity - Earnings Per Share Reconciliation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Partners' Capital [Abstract] | ||||
Net income (loss) | $ (1,327,929) | $ 130,643 | $ (1,692,461) | $ 16,160 |
Net (loss) income attributable to participating units | (31,662) | 1,868 | (40,612) | 40 |
Less: Distributions to Series A preferred unitholders | 4,125 | 4,125 | 12,375 | 5,958 |
Non-cash distributions to Series B preferred unitholders | 7,145 | 0 | 13,553 | 0 |
Net Income (Loss) Available to Common Stockholders, Basic | $ (1,307,537) | $ 124,650 | $ (1,677,777) | $ 10,162 |
Weighted average number of units used to calculate basic and diluted net loss per unit: | ||||
Common Units | 211,766 | 120,473 | 211,369 | 119,806 |
Dilutive units (in shares) | 0 | 777 | 0 | 738 |
Denominator for basic income (loss) per common unit (in shares) | 211,766 | 121,250 | 211,369 | 120,544 |
Net income (loss) per common unit | ||||
Basic income (in dollars per share) | $ (6.17) | $ 1.03 | $ (7.94) | $ 0.08 |
Diluted income (in dollars per share) | $ (6.17) | $ 1.03 | $ (7.94) | $ 0.08 |
Accumulated Other Comprehensi59
Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2015 | Sep. 30, 2015 | |
Accumulated Other Comprehensive Income [Roll Forward] | ||
Accumulated comprehensive loss attributable to the partnership, beginning of period | $ (333) | $ (392) |
Other comprehensive loss before reclassification | (637) | (390) |
Amounts reclassified from accumulated other comprehensive loss | 0 | (147) |
Net current period other comprehensive loss | (637) | (537) |
Noncontrolling Interest, Accumulated Other Comprehensive Income (loss) Net of Tax | (394) | (353) |
Accumulated comprehensive loss attributable to the partnership, end of period | (576) | (576) |
Available-For-Sale Securities | ||
Accumulated Other Comprehensive Income [Roll Forward] | ||
Accumulated comprehensive loss attributable to the partnership, beginning of period | (53) | (112) |
Other comprehensive loss before reclassification | (637) | (390) |
Amounts reclassified from accumulated other comprehensive loss | 0 | (147) |
Net current period other comprehensive loss | (637) | (537) |
Noncontrolling Interest, Accumulated Other Comprehensive Income (loss) Net of Tax | (394) | (353) |
Accumulated comprehensive loss attributable to the partnership, end of period | (296) | (296) |
Postretirement Benefits | ||
Accumulated Other Comprehensive Income [Roll Forward] | ||
Accumulated comprehensive loss attributable to the partnership, beginning of period | (280) | (280) |
Other comprehensive loss before reclassification | 0 | 0 |
Amounts reclassified from accumulated other comprehensive loss | 0 | 0 |
Net current period other comprehensive loss | 0 | 0 |
Noncontrolling Interest, Accumulated Other Comprehensive Income (loss) Net of Tax | 0 | 0 |
Accumulated comprehensive loss attributable to the partnership, end of period | $ (280) | $ (280) |
Unit and Other Valuation-Base60
Unit and Other Valuation-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense | $ 6,169,000 | $ 5,800,000 | $ 20,714,000 | $ 18,440,000 |
Fair market value of RPUs granted, average (in dollars per share) | $ 6.52 | $ 6.52 | ||
Payments related to taxes withheld on RPUs vested during the period | $ 0 | $ 700,000 | $ 900,000 | |
Total unrecognized compensation costs | 30,100,000 | 30,100,000 | ||
Restructuring Charges [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense | $ (191,000) | $ 1,343,000 | ||
Employee [Member] | Restricted Phantom Units (RPUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Grants in the period (in shares) | 0.1 | 4.7 | ||
Director [Member] | Restricted Phantom Units (RPUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Grants in the period (in shares) | 0 | 0.2 | ||
General and Administrative Expense [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense | $ 6,400,000 | $ 19,400,000 | ||
Restructuring Charges [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense | $ (200,000) | $ 1,300,000 |
Restructuring Costs (Details)
Restructuring Costs (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($)employee | Mar. 31, 2015USD ($)employee | Sep. 30, 2014USD ($) | Jun. 30, 2015USD ($) | Sep. 30, 2015USD ($)positon | Sep. 30, 2014USD ($) | |
Restructuring Reserve [Roll Forward] | |||||||
Restructuring Charges | $ (278) | $ 0 | $ 6,413 | $ 0 | |||
Severance Costs | 0 | 4,768 | |||||
Compensation expense | 6,169 | $ 5,800 | 20,714 | $ 18,440 | |||
Other restructuring costs | (87) | 302 | |||||
Restructuring Charges [Member] | |||||||
Restructuring Reserve [Roll Forward] | |||||||
Compensation expense | $ (191) | $ 1,343 | |||||
One-time Termination Benefits [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Number of positions eliminated | employee | 8 | 37 | |||||
March termination [Member] | |||||||
Restructuring Reserve [Roll Forward] | |||||||
Restructuring Charges | $ 4,900 | $ 5,600 | |||||
April termination [Member] | |||||||
Restructuring Reserve [Roll Forward] | |||||||
Restructuring Charges | $ 1,100 | ||||||
Number of Employees, Total [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Number of positions eliminated | positon | 60 |
Subsequent Events (Details)
Subsequent Events (Details) | Oct. 30, 2015Energy / DaysDays / bbl$ / shares$ / Energy$ / bbl | Oct. 01, 2015$ / shares | Sep. 30, 2015Energy / DaysDays / bbl$ / shares$ / Energy$ / bbl | Sep. 30, 2014$ / shares | Sep. 30, 2015Energy / DaysDays / bbl$ / shares$ / Energy$ / bbl | Sep. 30, 2014$ / shares |
Common Units [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares | $ 0.1250 | $ 0.5025 | $ 0.4999 | $ 1.4925 | ||
Preferred Units [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution made to limited partner, annual distribution (usd per share) | $ / shares | 2.0625 | |||||
Subsequent Event [Member] | Common Units [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution made to limited partner (usd per unit) | $ / shares | $ 0.04166 | $ 0.04166 | ||||
Subsequent Event [Member] | Preferred Units [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution made to limited partner (usd per unit) | $ / shares | 0.171875 | 0.171875 | ||||
Preferred Units B [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares | $ 0.02000 | $ 0.03489 | ||||
Preferred Units B [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares | $ 0.006666 | $ 0.006666 | ||||
Oil | Term of Calendar 2019 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | 0 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 0 | 0 | ||||
Oil | Term of Calendar 2018 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 493 | 493 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 82.20 | 82.20 | ||||
Oil | Term of Calendar 2017 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 13,817 | 13,817 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 85.32 | 85.32 | ||||
Oil | Term of Calendar 2016 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 22,804 | 22,804 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 89.01 | 89.01 | ||||
Oil | NYMEX WTI [Member] | Term of Calendar 2019 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 0 | 0 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 0 | 0 | ||||
Oil | NYMEX WTI [Member] | Term of Calendar 2018 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 493 | 493 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 82.20 | 82.20 | ||||
Oil | NYMEX WTI [Member] | Term of Calendar 2017 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 13,519 | 13,519 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 85.05 | 85.05 | ||||
Oil | NYMEX WTI [Member] | Term of Calendar 2017 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 1,000 | |||||
Oil | NYMEX WTI [Member] | Term of Calendar 2016 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 15,504 | 15,504 | ||||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 88.07 | 88.07 | ||||
Oil | NYMEX WTI [Member] | Term of Calendar 2016 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | Days / bbl | 2,000 | |||||
Derivative, Average floor price | $ / bbl | 49.10 | |||||
Derivative, Average Cap Price | $ / bbl | 56.35 | |||||
Natural Gas | Term of Calendar 2019 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 8,000 | 8,000 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.20 | 3.20 | ||||
Natural Gas | Term of Calendar 2018 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 15,870 | 15,870 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.26 | 3.26 | ||||
Natural Gas | Term of Calendar 2017 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 54,056 | 54,056 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.02 | 4.02 | ||||
Natural Gas | Term of Calendar 2016 [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 77,030 | 77,030 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.08 | 4.08 | ||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2019 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 8,000 | 8,000 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.20 | 3.20 | ||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2019 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 2,000 | |||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 2.95 | |||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2018 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 14,000 | 14,000 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.15 | 3.15 | ||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2018 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 3,500 | |||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 2.91 | |||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2017 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 24,000 | 24,000 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.71 | 3.71 | ||||
Natural Gas | Mich Con City-Gate [Member] | Term of Calendar 2016 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 29,000 | 29,000 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 3.91 | 3.91 | ||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2019 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 0 | 0 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 0 | 0 | ||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2018 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 1,870 | 1,870 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.15 | 4.15 | ||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2018 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 1,000 | |||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 2.99 | |||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2017 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 19,016 | 19,016 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.43 | 4.43 | ||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2017 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 2,000 | |||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2016 [Member] | Swap [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 36,050 | 36,050 | ||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 4.24 | 4.24 | ||||
Natural Gas | Henry Hub [Member] | Term of Calendar 2016 [Member] | Swap [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Derivative, Nonmonetary Notional Amount | 6,000 | |||||
Derivative, Swap Type, Average Fixed Price | $ / Energy | 2.67 |