Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Mar. 03, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | Vanguard Natural Resources, LLC | ||
Entity Central Index Key | 1,384,072 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 130,481,279 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 1,262,296,407 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||
Oil sales | $ 164,111 | $ 268,685 | $ 268,922 |
Natural gas sales | 193,496 | 285,439 | 124,513 |
Natural gas liquids sales | 39,620 | 70,489 | 49,813 |
Net gains on commodity derivative contracts | 169,416 | 163,452 | 11,256 |
Total revenues | 566,643 | 788,065 | 454,504 |
Production: | |||
Lease operating expenses | 146,654 | 132,515 | 105,502 |
Production and other taxes | 40,576 | 61,874 | 40,430 |
Depreciation, depletion, amortization and accretion | 247,119 | 226,937 | 167,535 |
Impairment of oil and natural gas properties | 1,842,317 | 234,434 | 0 |
Goodwill impairment loss | 71,425 | 0 | 0 |
Selling, general and administrative expenses | 55,076 | 30,839 | 25,942 |
Total costs and expenses | 2,403,167 | 686,599 | 339,409 |
Income (loss) from operations | (1,836,524) | 101,466 | 115,095 |
Other income (expense): | |||
Interest expense | (87,573) | (69,765) | (61,148) |
Net gains (losses) on interest rate derivative contracts | 153 | (1,933) | (96) |
Net gain on acquisitions of oil and natural gas properties | 40,533 | 34,523 | 5,591 |
Other | 237 | 54 | 69 |
Total other expense, net | (46,650) | (37,121) | (55,584) |
Net income (loss) | (1,883,174) | 64,345 | 59,511 |
Less: Distributions to Preferred unitholders | (26,759) | (18,197) | (2,634) |
Net income (loss) attributable to Common and Class B unitholders | $ (1,909,933) | $ 46,148 | $ 56,877 |
Net income (loss) per Common and Class B unit: | |||
Earnings Per Share, Basic | $ (19.80) | $ 0.56 | $ 0.78 |
Earnings Per Share, Diluted | $ (19.80) | $ 0.55 | $ 0.77 |
Weighted average units outstanding: | |||
Weighted average units outstanding - basic | 96,468 | 82,031 | 73,064 |
Weighted average units outstanding - diluted | 96,468 | 82,459 | 73,412 |
Common Units [Member] | |||
Weighted average units outstanding: | |||
Weighted average units outstanding - basic | 96,048 | 81,611 | 72,644 |
Weighted average units outstanding - diluted | 96,048 | 82,039 | 72,992 |
Class B Units [Member] | |||
Weighted average units outstanding: | |||
Weighted average units outstanding - basic and diluted | 420 | 420 | 420 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 0 | $ 0 |
Trade accounts receivable, net | 115,200 | 140,017 |
Derivative assets | 236,886 | 142,114 |
Other currents assets | 6,436 | 4,102 |
Total current assets | 358,522 | 286,233 |
Oil and natural gas properties, at cost | 4,961,218 | 4,140,527 |
Accumulated depletion, amortization and impairment | (3,239,242) | (1,164,721) |
Oil and natural gas properties evaluated, net – full cost method | 1,721,976 | 2,975,806 |
Other assets | ||
Goodwill | 506,046 | 420,955 |
Derivative assets | 80,161 | 83,583 |
Other assets | 42,592 | 27,015 |
Total assets | 2,709,297 | 3,793,592 |
Accounts payable: | ||
Trade | 22,895 | 15,118 |
Affiliates | 1,757 | 823 |
Accrued liabilities: | ||
Lease operating | 19,910 | 19,822 |
Developmental capital | 26,726 | 24,706 |
Interest | 11,958 | 11,517 |
Production and other taxes | 40,472 | 29,981 |
Other | 10,378 | 7,594 |
Derivative liabilities | 356 | 3,583 |
Oil and natural gas revenue payable | 44,823 | 40,117 |
Distributions payable | 5,018 | 18,640 |
Other current liabilities | 17,715 | 6,703 |
Total current liabilities | 202,008 | 178,604 |
Long-term debt | 2,291,636 | 1,932,816 |
Derivative liabilities | 0 | 1,380 |
Asset retirement obligations | 262,432 | 146,676 |
Other long-term liabilities | 40,656 | 0 |
Total liabilities | $ 2,796,732 | $ 2,259,476 |
Commitments and contingencies (Note 7) | ||
Members’ equity (deficit) | ||
Members’ equity (deficit) | $ (87,435) | $ 1,534,116 |
Total liabilities and members’ equity (deficit) | 2,709,297 | 3,793,592 |
Cumulative Preferred units | ||
Members’ equity (deficit) | ||
Members’ equity (deficit) | 335,444 | 335,444 |
Common Units [Member] | ||
Members’ equity (deficit) | ||
Members’ equity (deficit) | (430,494) | 1,191,057 |
Class B Units [Member] | ||
Members’ equity (deficit) | ||
Members’ equity (deficit) | $ 7,615 | $ 7,615 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2015 | Dec. 31, 2014 |
Members’ equity (deficit) | ||
Preferred units, outstanding | 13,881,873 | 13,881,873 |
Cumulative Preferred units | ||
Members’ equity (deficit) | ||
Preferred Unit, Issued | 13,881,873 | 13,881,873 |
Preferred units, outstanding | 13,881,873 | 13,881,873 |
Common Units [Member] | ||
Members’ equity (deficit) | ||
Common Unit, Issued | 130,476,978 | 83,451,746 |
Common Unit, Outstanding | 130,476,978 | 83,451,746 |
Class B Units [Member] | ||
Members’ equity (deficit) | ||
Common Unit, Issued | 420,000 | 420,000 |
Common Unit, Outstanding | 420,000 | 420,000 |
CONSOLIDATED STATEMENTS OF MEMB
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY - USD ($) $ in Thousands | Total | Common Units [Member]Member Units [Member] | Cumulative Preferred units | Cumulative Preferred unitsMember Units [Member] | Class B Units [Member]Member Units [Member] | EROC Merger [Member] | EROC Merger [Member]Common Units [Member]Member Units [Member] | LRE Merger [Member] | LRE Merger [Member]Common Units [Member]Member Units [Member] |
Balance at Dec. 31, 2012 | $ 797,464 | $ 789,849 | $ 7,615 | ||||||
Increase (Decrease) in Members' Equity (Deficit) | |||||||||
Issuance of units, net of offering costs | 498,360 | 498,360 | $ 61,021 | $ 61,021 | |||||
Partners' Capital Account, Distributions, Preferred Units | (2,634) | (2,634) | |||||||
Partners' Capital Account, Distributions, Common Units | (181,926) | (181,926) | |||||||
Unit-based compensation | 6,547 | 6,547 | |||||||
Partners' Capital Account, Acquisitions | 29,992 | 29,992 | |||||||
Net income (loss) | 59,511 | 59,511 | |||||||
Balance at Dec. 31, 2013 | 1,268,335 | 1,199,699 | 61,021 | 7,615 | |||||
Increase (Decrease) in Members' Equity (Deficit) | |||||||||
Issuance of units, net of offering costs | 147,814 | 147,814 | 274,423 | 274,423 | |||||
Stock Repurchased During Period, Value | (2,498) | (2,498) | |||||||
Partners' Capital Account, Distributions, Preferred Units | (18,197) | (18,197) | |||||||
Partners' Capital Account, Distributions, Common Units | (207,883) | (207,883) | |||||||
Unit-based compensation | 7,777 | 7,777 | |||||||
Net income (loss) | 64,345 | 64,345 | |||||||
Balance at Dec. 31, 2014 | 1,534,116 | 1,191,057 | 335,444 | 7,615 | |||||
Increase (Decrease) in Members' Equity (Deficit) | |||||||||
Issuance of units, net of offering costs | 35,544 | 35,544 | |||||||
Stock Repurchased During Period, Value | (2,399) | (2,399) | |||||||
Partners' Capital Account, Distributions, Preferred Units | $ (26,760) | (26,760) | |||||||
Partners' Capital Account, Distributions, Common Units | (134,019) | (134,019) | |||||||
Unit-based compensation | 16,874 | 16,874 | |||||||
Partners' Capital Account, Acquisitions | $ 253,068 | $ 253,068 | $ 119,315 | $ 119,315 | |||||
Net income (loss) | (1,883,174) | (1,883,174) | |||||||
Balance at Dec. 31, 2015 | $ (87,435) | $ (430,494) | $ 335,444 | $ 7,615 |
CONSOLIDATED STATEMENTS OF MEM6
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cumulative Preferred units | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 371 | $ 402 | |
Common Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 600 | ||
Common Units [Member] | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | 593 | $ 88 | $ 415 |
LRE Merger [Member] | Common Units [Member] | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | 5,560 | ||
EROC Merger [Member] | Common Units [Member] | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 3,961 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ / shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating activities | |||
Net income (loss) | $ (1,883,174) | $ 64,345 | $ 59,511 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 247,119 | 226,937 | 167,535 |
Impairment of oil and natural gas properties | 1,842,317 | 234,434 | 0 |
Goodwill impairment loss | 71,425 | 0 | 0 |
Amortization of deferred financing costs | 4,206 | 3,516 | 3,715 |
Amortization of debt discount | 1,071 | 269 | 248 |
Compensation related items | 16,874 | 10,706 | 5,931 |
Post Eagle Rock Merger severance costs | 13,955 | 0 | 0 |
Net gains on commodity and interest rate derivative contracts | (169,569) | (161,519) | (11,160) |
Net cash settlements received on matured commodity derivative contracts | 211,723 | 10,187 | 30,905 |
Net cash settlements paid on matured interest rate derivative contracts | (5,227) | (4,035) | (3,888) |
Cash received on termination of derivative contracts | 40,998 | 0 | 0 |
Net gain on acquisitions of oil and natural gas properties | (40,533) | (34,523) | (5,591) |
Changes in operating assets and liabilities: | |||
Trade accounts receivable | 53,423 | (69,908) | (22,065) |
Payables to affiliates | 934 | 574 | 217 |
Premiums paid on commodity derivative contracts | (4,235) | 0 | (204) |
Other current assets | (1,615) | (1,669) | (603) |
Accounts payable and oil and natural gas revenue payable | (555) | 22,166 | 16,426 |
Accrued expenses and other current liabilities | (43,320) | 29,377 | 18,855 |
Other assets | 14,267 | 8,895 | 1,133 |
Net cash provided by operating activities | 370,084 | 339,752 | 260,965 |
Investing activities | |||
Additions to property and equipment | (644) | (1,356) | (1,975) |
Additions to oil and natural gas properties | (112,639) | (142,015) | (56,661) |
Acquisitions of oil and natural gas properties and derivative contracts | (12,970) | (1,302,568) | (272,057) |
Cash acquired in the LRE and Eagle Rock Mergers | 18,503 | 0 | 0 |
Proceeds from the sale of oil and natural gas properties | 1,777 | 4,973 | 0 |
Deposits and prepayments of oil and natural gas properties | (22,171) | (5,236) | (67,284) |
Net cash used in investing activities | (128,144) | (1,446,202) | (397,977) |
Financing activities | |||
Proceeds from long-term debt | 420,000 | 1,388,000 | 589,500 |
Repayment of debt | (508,617) | (488,000) | (829,500) |
Proceeds from preferred unit offerings, net | 0 | 274,423 | 61,021 |
Proceeds from common unit offerings, net | 35,544 | 147,814 | 498,360 |
Repurchase of units under the common unit buyback program | (2,399) | (2,498) | 0 |
Distributions to Preferred unitholders | (26,760) | (17,290) | (2,426) |
Distributions to Common and Class B members | (147,641) | (206,649) | (177,555) |
Financing fees | (12,067) | (1,168) | (2,133) |
Net cash provided by (used in) financing activities | (241,940) | 1,094,632 | 137,267 |
Net increase (decrease) in cash and cash equivalents | 0 | (11,818) | 255 |
Cash and cash equivalents, beginning of year | 0 | 11,818 | 11,563 |
Cash and cash equivalents, end of year | 0 | 0 | 11,818 |
Supplemental cash flow information: | |||
Cash paid for interest | 83,557 | 66,434 | 57,067 |
Non-cash financing and investing activities: | |||
Asset retirement obligations | 25,028 | 56,947 | 22,692 |
Assets acquired under financing obligations | $ 31,502 | ||
Noncash or Part Noncash Acquisition, Accounts Receivable And Other Current Assets Acquired | 44,201 | ||
Net derivative assets acquired in a business combination | $ 166,758 | ||
Oil and gas properties acquired in a merger | $ 672,178 | ||
Noncash or Part Noncash Acquisition, Other Assets Acquired | $ 10,001 | ||
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed | 70,085 | ||
Asset retirement obligations assumed in a business combination | 88,228 | ||
Noncash or Part Noncash Acquisition, Debt Assumed | 446,550 | ||
Noncash or Part Noncash Acquisition, Payables Assumed | 40,571 | ||
Noncash or Part Noncash Acquisition, Noncash Financial or Equity Instrument Consideration, Value Issued | $ 381,904 | ||
Common units issued for the acquisition of oil and gas properties | $ 29,992 |
Description of the Business
Description of the Business | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of the Business | Description of the Business: Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of December 31, 2015 , we own properties and oil and natural gas reserves primarily located in ten operating basins: • the Green River Basin in Wyoming; • the Permian Basin in West Texas and New Mexico; • the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama; • the Anadarko Basin in Oklahoma and North Texas; • the Piceance Basin in Colorado; • the Big Horn Basin in Wyoming and Montana; • the Arkoma Basin in Arkansas and Oklahoma; • the Williston Basin in North Dakota and Montana; • the Wind River Basin in Wyoming; and • the Powder River Basin in Wyoming. References in this report to “us,” “we,” “our,” the “Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Clear Fork Pipeline LLC, Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Energy Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Energy Acquisition Partnership II, L.P. (“ERAP II”). |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies (a) Basis of Presentation and Principles of Consolidation: Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity. (b) New Pronouncement Issued But Not Yet Adopted: In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17 Income taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. (c) Cash Equivalents: The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. (d) Accounts Receivable and Allowance for Doubtful Accounts: Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. (e) Inventory: Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets. (f) Oil and Natural Gas Properties: The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and natural gas liquids (“NGLs”) reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (the “12-month average price”), discounted at 10% , plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015 . Such impairment was recognized during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2015 $ 132,610 $3.91 $82.62 Second quarter 2015 $ 733,365 $3.44 $71.51 Third quarter 2015 $ 491,487 $3.11 $59.23 Fourth quarter 2015 $ 484,855 $2.62 $50.20 Total $ 1,842,317 The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2015 were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date of December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisition date) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. (g) Goodwill and Other Intangible Assets: We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” 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 on October 1 or whenever indicators of impairment exist using a two-step process. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach based on our quoted common unit price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary. If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. In addition, if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test is performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, we evaluate any adverse qualitative factors. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. As described above, the key inputs used in estimating the fair value of our reporting unit are our common unit price, number of common units outstanding and a control premium. There is no uncertainty associated with our common unit price and number of common units outstanding. The control premium is based on market data of actual control premiums in our industry. Changes in the common unit price, which could result from further significant declines in the prices of oil and natural gas or significant negative reserve adjustments, or changes in market data as it relates to control premiums in the oil and gas extraction industry could change our estimate of the fair value of the reporting unit and could result in a non-cash impairment charge. We performed our annual impairment tests during 2015 , 2014 and 2013 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed interim impairment tests at December 31, 2015 and 2014. As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million . Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional impairment charge. Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2015 , the net carrying value of this contract was $8.1 million . The carrying value is shown as Other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year. (h) Asset Retirement Obligations: We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations. (i) Revenue Recognition and Gas Imbalances: Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, our revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2015 or 2014 . (j) Concentrations of Credit Risk: Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset. At December 31, 2015 and 2014 , the cash and cash equivalents were primarily concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal. The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales for the years ended December 31: 2015 2014 2013 Mieco, Inc 20% —% —% Anadarko Petroleum Corporation 2% 19% 1% Marathon Oil Company 7% 12% 14% Plains Marketing L.P. 7% 7% 10% Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions. (k) Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. (l) Price and Interest Rate Risk Management Activities: We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 3) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2015 , our derivative transactions included the following: • Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty. • Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. • Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity. • Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. • Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years. • Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Put spread options - created when we purchase a put and sell a put simultaneously. • Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the change in the fair value of the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. Gains or losses on derivative contracts that do not qualify for hedge accounting treatment are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations. We have elected not to designate our current portfolio of derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations. Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. (m) Income Taxes: The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However, the tax basis of our net assets exceeded the net book basis by $1.3 billion and $187.0 million at December 31, 2015 and 2014 , respectively. Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.2 million as of December 31, 2015 and 2014 and a deferred tax asset of $0.5 million and $0.3 million as of December 31, 2015 and 2014 , respectively. Tax benefits of $0.3 million and $0.6 million and a tax provision of $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2015 , 2014 , and 2013 , respectively, as a component of Selling, general and administrative expenses. The Company’s provision for income taxes also relates to the federal taxes for ERAC and ERAC II and their wholly owned corporations, ERUD and ERUD II, which are subject to federal income taxes (the “C Corporations”). As part of the Eagle Rock Merger, the Company assumed deferred tax liabilities, the largest single component of which is related to federal income taxes of the C Corporations, where the book/tax differences were created by certain acquisitions completed by ERAC and ERAC II prior to the Eagle Rock Merger. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. As of December 31, 2015 , the Company recorded a deferred tax liability of $39.4 million related to these C Corporations, which is included in the other long-term liabilities line item in the Consolidated Balance Sheet. The Company also recorded a net deferred tax asset of $2.2 million from the Eagle Rock Merger related to the book/tax differences in property, plant and equipment and hedging transactions, which is included in the other assets line item in the Consolidated Balance Sheet. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers t |
Acquisitions and Divestiture
Acquisitions and Divestiture | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions and Divestiture | Acquisitions and Divestiture Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, 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 dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below. On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million , subject to additional customary post-closing adjustments to be determined based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. 2015 Mergers LRE Merger On October 5, 2015 , we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C”), and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”), the general partner of LRE. Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE common units”) was converted into the right to receive 0.550 newly issued Vanguard common units. As consideration for the LRE Merger, we issued approximately 15.4 million Vanguard common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. As consideration for our purchase of the limited liability company interests in LRE GP, we issued 12,320 Vanguard common units. The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units. Consideration Market value of Vanguard’s common units issued to LRE unitholders $ 123,276 Long-term debt assumed 290,000 413,276 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 5,606 Other current liabilities 9,018 Asset retirement obligations 39,595 Amount attributable to liabilities assumed 54,219 Less: fair value of assets acquired Cash 11,532 Trade accounts receivable 6,822 Other current assets 4,172 Oil and natural gas properties 209,463 Derivative assets 78,725 Other assets 267 Amount attributable assets acquired 310,981 Goodwill $ 156,514 Eagle Rock Merger On October 8, 2015 , we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”). Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock common unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent). As consideration for the Eagle Rock Merger, Vanguard issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price per Vanguard common unit of $9.31 at October 8, 2015 and assumed $156.6 million in debt. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of Eagle Rock Merger. The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock common units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock common units in connection with the Eagle Rock Merger. Consideration Market value of Vanguard’s common units issued to Eagle Rock unitholders $ 258,282 Long-term debt assumed 156,550 Replacement share-based payment awards attributable to pre-combination services 346 415,178 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 53,255 Other current liabilities 2,206 Derivative liabilities 2,201 Asset retirement obligations 48,633 Deferred tax liability 39,327 Other long-term liabilities 1,244 Amount attributable to liabilities assumed 146,866 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 17,543 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable assets acquired 602,861 Bargain Purchase Gain $ (40,817 ) As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the Eagle Rock Merger. Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock merger, including the oil and natural gas properties, exceeded the total consideration paid. 2014 Acquisitions Pinedale Acquisition On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013 . We refer to this acquisition as the “Pinedale Acquisition.” In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million , as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 600,123 Inventory 244 Asset retirement obligations (12,404 ) Imbalance liabilities (171 ) Other (125 ) Total fair value of assets and liabilities acquired 587,667 Fair value of consideration transferred 555,553 Gain on acquisition $ 32,114 Piceance Acquisition On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. We refer to this acquisition as the “Piceance Acquisition.” Through this acquisition, we acquired additional interests in the same properties previously acquired in the Rockies acquisition completed in June 2012. The purchase price is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million , as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 521,401 Asset retirement obligations (19,452 ) Imbalance and suspense liabilities (236 ) Total fair value of assets and liabilities acquired 501,713 Fair value of consideration transferred 502,140 Loss on acquisition $ (427 ) Other Acquisitions On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and net cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014 . On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million , subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014 . During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million . 2013 Acquisitions On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in southeast New Mexico and West Texas for an adjusted purchase price of $266.2 million . This acquisition had an effective date of January 1, 2013 . On June 28, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in Texas and the San Juan and DJ-Basin in Colorado with an effective date of July 1, 2013 for an adjusted purchase price of $29.9 million . The consideration for this acquisition was paid in common equity by issuing 1,075,000 VNR common units, at an agreed price of $27.65 per common unit, valued for financial reporting purposes at the closing price of $27.90 at the closing date of the acquisition. We also completed other acquisitions during 2013 including the acquisition of additional working interests in previously acquired properties for an aggregate adjusted purchase price of $2.5 million . The following presents the values assigned to the net assets acquired in our 2013 acquisitions: Fair value of assets and liabilities acquired: (in thousands) Oil and natural gas properties $ 317,573 Inventory 899 Asset retirement obligations (11,381 ) Oil and natural gas revenue payable and imbalance liabilities (2,843 ) Total fair value of assets and liabilities acquired 304,248 Fair value of consideration transferred 298,657 Gain on acquisition $ 5,591 Pro Forma Operating Results (Unaudited) In accordance with ASC Topic 805, presented below are unaudited pro forma results for the years ended December 31, 2015 , 2014 and 2013 which reflect the effect on our consolidated results of operations as if (i) all our acquisitions in 2015 had occurred on January 1, 2014 , (ii) all our acquisitions in 2014 had occurred on January 1, 2013 and (iii) all our acquisitions in 2013 had occurred on January 1, 2012. The pro forma results reflect the results of combining our Consolidated Statements of Operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (i) assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired using the acquisition method of accounting, (iii) interest expense on additional borrowings necessary to finance the acquisitions and additional debt assumed in the LRE and Eagle Rock Mergers, and (iv) the impact of the common units issued in the acquisition of properties completed on June 28, 2013 and the common units issued in the LRE and Eagle Rock Mergers. The net gain (loss) on acquisitions of oil and natural gas properties were excluded from the pro forma results. The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations: Year Ended December 31, 2015 2014 2013 (in thousands, except per unit amounts) (Pro forma) Total revenues $ 804,564 $ 1,430,710 $ 841,576 Net income (loss) attributable to Common and Class B unitholders $ (2,057,879 ) $ (66,405 ) $ 161,329 Net income (loss) attributable to Common and Class B unitholders, per unit: Basic $ (15.83 ) $ (0.53 ) $ 2.19 Diluted $ (15.83 ) $ (0.53 ) $ 2.17 Post-Acquisition Operating Results The results of operations of the properties acquired, as described above, have been included in our consolidated financial statements from the closing dates of the acquisitions forward. The table below presents the amounts of revenues and excess of revenues over direct operating expenses included in our 2015 , 2014 and 2013 Consolidated Statements of Operations for our acquisitions. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes. Year Ended December 31, 2015 2014 2013 (in thousands) LRE Acquisition Revenues $ 13,083 $ — $ — Excess of revenues over direct operating expenses $ 6,029 $ — $ — Eagle Rock Acquisition Revenues $ 23,005 $ — $ — Excess of revenues over direct operating expenses $ 15,112 $ — $ — Pinedale Acquisition Revenues $ 84,934 $ 139,908 $ — Excess of revenues over direct operating expenses $ 56,672 $ 107,934 $ — Piceance Acquisition Revenues $ 37,767 $ 22,642 $ — Excess of revenues over direct operating expenses $ 18,427 $ 15,234 $ — All other acquisitions Revenues $ 58,718 $ 76,915 $ 34,820 Excess of revenues over direct operating expenses $ 30,373 $ 50,317 $ 23,160 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Our financing arrangements consisted of the following: Amount Outstanding December 31, Description Interest Rate Maturity Date 2015 2014 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,688,000 $ 1,360,000 Senior Notes due 2020 7.875% (2) April 1, 2020 550,000 550,000 Senior Notes due 2019 8.375% (3) June 1, 2019 51,120 — Lease Financing Obligations 4.16% (4) August 10, 2020 (4) 24,668 28,986 $ 2,313,788 $ 1,938,986 Less: Unamortized discount on Senior Notes (17,651 ) (1,852 ) Current portion (4,501 ) (4,318 ) Total long-term debt $ 2,291,636 $ 1,932,816 (1) Variable interest rate was 2.90% and 2.17% at December 31, 2015 and 2014 , respectively. (2) Effective interest rate is 8.0% . (3) Effective interest rate is 21.45% . (4) The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021. Senior Secured Reserve-Based Credit Facility The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and a borrowing base of $1.8 billion (the “Reserve-Based Credit Facility”) with a maturity date of April 16, 2018. On December 31, 2015 , there were $1.69 billion of outstanding borrowings and $107.5 million of borrowing capacity under the Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit (discussed below). On June 3, 2015, the Company entered into the Eighth Amendment to the Credit Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion. However, the Eighth Amendment provided for an automatic increase in the borrowing base of $200.0 million upon the closing of the LRE Merger, which took place on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, an amendment of the consolidated leverage ratio whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond. On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Ninth Amendment to the Credit Agreement, which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Ninth Amendment to the Credit Agreement also include, among other provisions, the increase in the maximum investments or capital contributions that can be made in certain entities from $5.0 million to $100.0 million . In addition, the Company is permitted to incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 per dollar of junior debt issued. Interest rates under the Reserve-Based Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At December 31, 2015 , the applicable margins and other fees increase as the utilization of the borrowing base increases as follows: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% > 25% <50% > 50% <75% > 75% <90% > 90% Eurodollar Loans Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % ABR Loans Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % Commitment Fee Rate 0.50 % 0.50 % 0.375 % 0.375 % 0.375 % Letter of Credit Fee 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our consolidated leverage ratio to be more than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At December 31, 2015 , we were in compliance with all of our debt covenants. Our next borrowing base redetermination is scheduled for April 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant. Letters of Credit At December 31, 2015 , we had unused irrevocable standby letters of credit of approximately $4.5 million . The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks. 7.875% Senior Notes Due 2020 At December 31, 2015 , we had $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes Due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes due 2020 (the “Senior Notes Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes due 2020, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Notes Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Notes Indenture, (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us. The Senior Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Indenture exists, many of the foregoing covenants will terminate. At December 31, 2015 , based on the most restrictive covenants of the Senior Notes Indenture, our cash balance and the borrowings available under the Reserve-Based Credit Facility, $23.0 million of members’ equity is available for distributions to unitholders, while the remainder is restricted. Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016 , plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes due 2020 at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium, and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively. Debt Exchange On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of their outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. See Note 12. Subsequent Events for further discussion. 8.375% Senior Notes Due 2019 In connection with the Eagle Rock Merger, VO assumed 8.375% senior notes with a principal amount of $51.1 million due in 2019 (the “Senior Notes due 2019”) with a fair market value of $34.3 million as of the close date of the Eagle Rock Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of its Subsidiary Guarantors. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 will mature on June 1, 2019. We have the option to redeem some or all of the Senior Notes due 2019 at any time at redemption prices equal to the aggregate principal amount multiplied by (i) 102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if such Senior Notes due 2019 are redeemed in 2017 and thereafter. Lease Financing Obligations On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option where the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16% . |
Price and Interest Rate Risk Ma
Price and Interest Rate Risk Management Activities | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price and Interest Rate Risk Management Activities | Price and Interest Rate Risk Management Activities We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. At December 31, 2015 , the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps (West Texas Intermediate) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average Fixed Price January 1, 2016 – December 31, 2016 69,996,888 $ 4.43 1,875,531 $ 84.01 906,900 $ 30.31 January 1, 2017 – December 31, 2017 31,112,760 $ 4.33 749,698 $ 85.70 — $ — Fixed-Price Swaps (Light Louisiana Sweet) Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2017 – December 31, 2017 168,000 $ 91.25 Call Options Sold Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2016 – December 31, 2016 622,200 $ 125.00 January 1, 2017 – December 31, 2017 365,000 $ 95.00 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index January 1, 2016 – December 31, 2016 38,430,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2017 – December 31, 2017 10,950,000 $ (0.22 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index January 1, 2016 – December 31, 2016 968,700 $ (1.01 ) WTI Midland and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 219,600 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 716,500 $ (14.26 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMbtu Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 12,810,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 16,425,000 $ 3.92 $ 4.23 $ 3.37 Oil Contract Period Bbls Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 1,061,400 $ 90.00 $ 96.18 $ 73.62 Puts Oil Contract Period Bbls Put Price ($/Bbl) January 1, 2016 – December 31, 2016 366,000 $ 60.00 Put Options Sold Gas Oil Contract Period MMbtu Put Sold ($/MMbtu) Bbls Put Sold ($/Bbl) January 1, 2016 – December 31, 2016 1,830,000 $ 3.00 146,400 $ 50.00 January 1, 2017 – December 31, 2017 1,825,000 3.50 73,000 $ 75.00 Range Bonus Accumulators Oil Contract Period Bbls Bonus Range Ceiling Range Floor January 1, 2016 – December 31, 2016 183,000 $ 4.00 $ 100.00 $ 75.00 Interest Rate Swaps We may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. These interest rate swap agreements require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. If LIBOR is lower than the fixed rate in the contract, we are required to pay the counterparty the difference, and conversely, the counterparty is required to pay us if LIBOR is higher than the fixed rate in the contract. We do not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. At December 31, 2015 , the Company had open interest rate derivative contracts as follows (in thousands): Notional Amount Fixed LIBOR Rates Period: January 1, 2016 to December 10, 2016 $ 20,000 2.17 % January 1, 2016 to October 31, 2016 $ 40,000 1.65 % January 1, 2016 to August 5, 2018 $ 30,000 2.25 % January 1, 2016 to August 6, 2016 $ 25,000 1.80 % January 1, 2016 to October 31, 2016 $ 20,000 1.78 % January 1, 2016 to September 23, 2016 $ 75,000 1.15 % January 1, 2016 to March 7, 2016 $ 75,000 1.08 % January 1, 2016 to September 7, 2016 $ 25,000 1.25 % January 1, 2016 to December 31, 2019 $ 175,000 2.32 % January 1, 2016 to February 16, 2017 $ 75,000 1.73 % January 1, 2016 to June 16, 2017 $ 70,000 1.43 % January 1, 2016 to February 16, 2017 $ 75,000 1.73 % Total $ 705,000 Balance Sheet Presentation Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 349,281 $ (21,834 ) $ 327,447 Interest rate derivative contracts — (10,400 ) (10,400 ) Total derivative instruments $ 349,281 $ (32,234 ) $ 317,047 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (21,934 ) $ 21,834 $ (100 ) Interest rate derivative contracts (10,656 ) 10,400 (256 ) Total derivative instruments $ (32,590 ) $ 32,234 $ (356 ) December 31, 2014 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts 289,018 (63,321 ) 225,697 Total derivative instruments $ 289,018 $ (63,321 ) $ 225,697 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (63,615 ) $ 63,321 $ (294 ) Interest rate derivative contracts (4,669 ) — (4,669 ) Total derivative instruments $ (68,284 ) $ 63,321 $ (4,963 ) By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (see Note 3 for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $349.3 million at December 31, 2015 . In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of December 31, 2015 . We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2015 , 2014 and 2013 is as follows: 2015 2014 2013 (in thousands) Derivative asset at January 1, net $ 220,734 $ 66,711 $ 82,568 Purchases Fair value of derivatives acquired 195,273 (1,344 ) — Premiums and fees paid or deferred for derivative contracts during the period 7,126 — — Net gains on commodity and interest rate derivative contracts 169,569 161,519 11,160 Settlements Net cash settlements received on matured commodity derivative contracts (211,723 ) (10,187 ) (30,905 ) Net cash settlements paid on matured interest rate derivative contracts 5,227 4,035 3,888 Termination of derivative contracts (69,515 ) — — Derivative asset at December 31, net $ 316,691 $ 220,734 $ 66,711 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “ Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value. We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets and the initial measurement of asset retirement obligations. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process. The standard describes three levels of inputs that may be used to measure fair value: Level 1 Quoted prices for identical instruments in active markets. Level 2 Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 3 Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Financing arrangements. The carrying amounts of our bank borrowings outstanding approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. The fair value of the Lease Financing Obligations is measured using market-based parameters of comparable term secured financing instruments and therefore we estimate that the carrying value approximates its fair value. The fair value measurements for our bank borrowings and the Lease Financing Obligations represent Level 2 inputs. As of December 31, 2015 , the fair value of our Senior Notes due 2020 was estimated to be $165.4 million and our Senior Notes due 2019 was estimated to be $14.4 million . We consider the inputs to the valuation of both our Senior Notes due 2020 and our Senior Notes due 2019 to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution. Derivative instruments. As of December 31, 2015 , our commodity derivative instruments consist of fixed-price swaps, basis swap contracts, three-way collars, call options sold, put options sold and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps and basis swap contracts based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option values of the contract floors, ceilings, collars and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rates used in the discounted cash flow projections are based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair values of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimates for these derivative instruments as a Level 2 input. We estimate the values of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuations may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimates for range bonus accumulators as a Level 3 input. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives. Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): December 31, 2015 Fair Value Measurements Using Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 (in thousands) Assets: Commodity price derivative contracts $ — $ 333,380 $ (5,933 ) $ 327,447 Interest rate derivative contracts — (10,400 ) — (10,400 ) Total derivative instruments $ — $ 322,980 $ (5,933 ) $ 317,047 Liabilities: Commodity price derivative contracts $ — $ (99 ) $ — $ (99 ) Interest rate derivative contracts — (257 ) — (257 ) Total derivative instruments $ — $ (356 ) $ — $ (356 ) December 31, 2014 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value (in thousands) Assets: Commodity price derivative contracts $ — $ 232,167 $ (6,470 ) $ 225,697 Total derivative instruments $ — $ 232,167 $ (6,470 ) $ 225,697 Liabilities: Commodity price derivative contracts $ — $ (294 ) $ — $ (294 ) Interest rate derivative contracts — (4,669 ) — (4,669 ) Total derivative instruments $ — $ (4,963 ) $ — $ (4,963 ) The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: 2015 2014 (in thousands) Unobservable inputs at January 1, $ (6,470 ) $ 566 Total gains (losses) 5,151 (8,238 ) Settlements (4,614 ) 1,202 Unobservable inputs at December 31, $ (5,933 ) $ (6,470 ) Change in fair value included in earnings related to derivatives still held as of December 31, $ (2,925 ) $ (6,326 ) During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimates of the fair value of our reporting unit and could result in an impairment charge. As of December 31, 2015, the Company performed the second step of the goodwill impairment test. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties include: (i) observable forward prices for commodities at December 31, 2015 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units. Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations. These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the years ended December 31, 2015 and 2014 , in connection with the oil and natural gas properties acquired in all of our acquisitions, the LRE and Eagle Rock Mergers, as well as new wells drilled during each year, we incurred and recorded asset retirement obligations totaling $90.9 million and $52.8 million , respectively, at fair value. We also recorded a $22.3 million and a $4.1 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the years ended December 31, 2015 and 2014 , respectively. The fair value of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.6% and 5.5% ; and (4) the average inflation factor ( 2.0% ). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The asset retirement obligations as of December 31 , reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31 , were as follows: 2015 2014 (in thousands) Asset retirement obligation at January 1, $ 149,062 $ 87,967 Liabilities added during the current period 2,699 52,829 Liabilities added from the LRE and Eagle Rock Mergers 88,228 — Accretion expense 10,238 5,889 Change in estimate 22,329 4,118 Disposition of properties (262 ) (1,291 ) Retirements (838 ) (450 ) Total asset retirement obligation at December 31, 271,456 149,062 Less: current obligations (9,024 ) (2,386 ) Long-term asset retirement obligation at December 31, $ 262,432 $ 146,676 Accretion expense for the years ended December 31, 2015 , 2014 and 2013 was $10.2 million , $5.9 million and $2.8 million , respectively. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2015 and 2014 , we reviewed the actual abandonment costs with previous estimates and, as a result, increased our estimates of future asset retirement obligations by a net $22.3 million and $4.1 million , respectively, to reflect increased costs incurred for plugging and abandonment on certain wells. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Transportation Demand Charges As of December 31, 2015 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to five years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize. The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2015 . However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. (in thousands) 2016 $ 14,957 2017 12,512 2018 11,696 2019 9,661 2020 410 Thereafter — Total $ 49,236 Development Commitments We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. Total estimated costs to be spent in 2016 is approximately $38.0 million . Legal Proceedings We are defendants in certain legal proceedings arising in the normal course of our business. We are also a party to separate legal proceedings relating to each of the LRE Merger, the Eagle Rock Merger and our debt exchange. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. |
Members' Equity (Deficit) and N
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Members’ Equity (Deficit) and Net Income (Loss) per Common and Class B Unit | Members’ Equity (Deficit) and Net Income (Loss) per Common and Class B Unit Cumulative Preferred Units The following table summarizes the Company’s Cumulative Preferred Units outstanding at December 31, 2015 and 2014 : 2015 2014 Earliest Redemption Date Liquidation Preference Per Share Distribution Rate Units Outstanding Carrying Value Units Outstanding Carrying Value Series A June 15, 2023 $25.00 7.875% 2,581,873 $ 62,200 2,581,873 $ 62,200 Series B April 15, 2024 $25.00 7.625% 7,000,000 $ 169,265 7,000,000 $ 169,265 Series C October 15, 2024 $25.00 7.75% 4,300,000 $ 103,979 4,300,000 $ 103,979 Total Cumulative Preferred Units 13,881,873 $ 335,444 13,881,873 $ 335,444 The Series A, B and C Cumulative Preferred Units (collectively the “Cumulative Preferred Units”) have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above. Common and Class B Units The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units. On October 15, 2014, our board of directors authorized a $10.0 million common unit buyback program. The program was approved for an initial three month period and authorized us to make open market purchases pursuant to the Securities and Exchange Commission guidelines of Rule 10b-18 promulgated under the Securities Exchange Act of 1934, as amended. We intend to hold the common units to fund our VNR LTIP (defined in Note 10) as directed by the Compensation Committee. As of December 31, 2015 , since its inception, we have repurchased a total of 291,926 units under the common unit buyback program for an aggregate cost of $4.9 million . The following is a summary of the changes in our common units issued during the years ended December 31, 2015 , 2014 and 2013 (in thousands): 2015 2014 2013 Beginning of period 83,452 78,337 58,706 Issuance of Common units as consideration for the Eagle Rock Merger 27,886 — — Issuance of Common units as consideration for the LRE Merger 15,448 — — Issuance of Common units for the acquisition of oil and natural gas properties — — 1,075 Issuance of Common units for cash 2,430 4,864 18,377 Repurchase of units under the common unit buyback program (157 ) (135 ) — Unit-based compensation 1,418 386 179 End of period 130,477 83,452 78,337 There was no change in issued and outstanding Class B units during the years ended December 31, 2015 , 2014 and 2013 . Net Income (Loss) per Common and Class B Unit Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “ Earnings Per Share ” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of net income per unit. The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows (in thousands, except per unit data): 2015 (a) 2014 2013 Net income (loss) attributable to Common and Class B unitholders $ (1,909,933 ) $ 46,148 $ 56,877 Weighted average number of Common and Class B units outstanding - basic 96,468 82,031 73,064 Effect of dilutive securities: Phantom units — 428 348 Weighted average number of Common and Class B units outstanding - diluted 96,468 82,459 73,412 Net income (loss) per Common and Class B unit Basic $ (19.80 ) $ 0.56 $ 0.78 Diluted $ (19.80 ) $ 0.55 $ 0.77 (a) For the year ended December 31, 2015, 164,984 phantom units were excluded from the calculation of diluted earnings per unit due to their antidilutive effect as we were in a loss position. Distributions Declared The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Cumulative Preferred Units are cumulative from the date of original issue and payable monthly in arrears on the 15th day of each month of each year, unless the 15th day falls on a weekend or holiday, in which case it will be paid on the next business day, when, as and if declared by our board of directors. Distributions on our Cumulative Preferred Units accumulate at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit. We reduced our cash distribution per common unit to $0.03 starting with the cash distribution attributable to the month of November 2015, or $0.36 per unit on an annualized basis. This amount represents a reduction from the payment for the month of October 2015, which was $0.1175 per common unit or $1.41 per unit on an annualized basis. This new distribution rate takes into consideration current commodity and financial market conditions and helps to preserve our liquidity that will be directed at paying down debt under our Reserve-Based Credit Facility. On January 20, 2016 and February 18, 2016 , our board of directors declared cash distributions on the Cumulative Preferred Units and common and Class B units attributable to the month of December 2015 and January 2016, respectively. Also, on February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Our ability to resume distributions is at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. See Note 12. Subsequent Events for further discussion. The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2015 Fourth Quarter November $ 0.0300 December 18, 2015 January 4, 2016 January 14, 2016 October $ 0.1175 November 20, 2015 December 1, 2015 December 15, 2015 Third Quarter September $ 0.1175 October 19, 2015 November 2, 2015 November 13, 2015 August $ 0.1175 September 21, 2015 October 1, 2015 October 15, 2015 July $ 0.1175 August 20, 2015 September 1, 2015 September 14, 2015 Second Quarter June $ 0.1175 July 16, 2015 August 3, 2015 August 14, 2015 May $ 0.1175 June 18, 2015 July 1, 2015 July 15, 2015 April $ 0.1175 May 19, 2015 June 1, 2015 June 12, 2015 First Quarter March $ 0.1175 April 15, 2015 May 1, 2015 May 15, 2015 February $ 0.1175 March 18, 2015 April 1, 2015 April 14, 2015 January $ 0.1175 February 17, 2015 March 2, 2015 March 17, 2015 2014 Fourth Quarter December $ 0.2100 January 22, 2015 February 2, 2015 February 13, 2015 November $ 0.2100 December 16, 2014 January 2, 2015 January 14, 2015 October $ 0.2100 November 20, 2014 December 1, 2014 December 15, 2014 Third Quarter September $ 0.2100 October 20, 2014 November 3, 2014 November 14, 2014 August $ 0.2100 September 19, 2014 October 1, 2014 October 15, 2014 July $ 0.2100 August 19, 2014 September 2, 2014 September 12, 2014 Second Quarter June $ 0.2100 July 16, 2014 August 1, 2014 August 14, 2014 May $ 0.2100 June 24, 2014 July 1, 2014 July 15, 2014 April $ 0.2100 May 20, 2014 June 2, 2014 June 13, 2014 First Quarter March $ 0.2100 April 17, 2014 May 1, 2014 May 15, 2014 February $ 0.2100 March 17, 2014 April 1, 2014 April 14, 2014 January $ 0.2075 February 2, 2014 March 3, 2014 March 17, 2014 2013 Fourth Quarter December $ 0.2075 January 16, 2014 February 3, 2014 February 14, 2014 November $ 0.2075 December 17, 2013 January 2, 2014 January 15, 2014 October $ 0.2075 November 19, 2013 December 2, 2013 December 13, 2013 Third Quarter September $ 0.2075 October 21, 2013 November 1, 2013 November 14, 2013 August $ 0.2075 September 12, 2013 October 1, 2013 October 15, 2013 July $ 0.2075 August 20, 2013 September 3, 2013 September 13, 2013 Second Quarter June $ 0.2050 July 18, 2013 August 1, 2013 August 14, 2013 May $ 0.2050 June 20, 2013 July 1, 2013 July 15, 2013 April $ 0.2050 April 30, 2013 June 3, 2013 June 14, 2013 First Quarter March $ 0.2025 April 19, 2013 May 1, 2013 May 15, 2013 February $ 0.2025 March 21, 2013 April 1, 2013 April 12, 2013 January $ 0.2025 February 18, 2013 March 1, 2013 March 15, 2013 2012 Fourth Quarter December $ 0.2025 January 25, 2013 February 4, 2013 February 14, 2013 |
Unit-Based Compensation
Unit-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Unit-Based Compensation Notes Disclosure | Unit-Based Compensation Long-Term Incentive Plan The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the board of directors of the Company to compensate employees, consultants, and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights. Restricted and Phantom Units A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding. The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. Executive Employment Agreements and Annual Bonus In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ended on January 1, 2016. The three executives have entered into an Amended and Restated Employment Agreement effective January 1, 2016 and ending on January 1, 2019. The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. As of December 31, 2015 , an accrued liability was recognized and compensation expense of $1.1 million was recorded for the year ended December 31, 2015 , related to these bonus arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations. Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. The restricted units and phantom units granted to executives under the Amended Agreements are subject to a three -year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units include a tandem grant of DERs. Restricted Unit Grants In January 2015, the executives were granted a total of 360,762 restricted units in accordance with the Amended Agreements. Also, during the year ended December 31, 2015 , our three independent board members were granted a total of 26,334 restricted units which will vest one year from the date of grant. The restricted units granted to the executives and our board members are accompanied by DERs. During 2015, VNR employees were also granted a total of 175,297 restricted units under the VNR LTIP of which 1,613 restricted units vested immediately. The remaining grants have vesting periods between three to four years from the date of grant. As of December 31, 2015 , a summary of the status of the non-vested restricted units under the VNR LTIP is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested units at December 31, 2014 440,047 $ 28.87 Granted 562,393 $ 15.17 Forfeited (17,670 ) $ 20.54 Non-vested Eagle Rock LTIP units replaced with VNR LTIP restricted units 143,647 $ 9.01 Vested (152,069 ) $ 26.04 Non-vested units at December 31, 2015 976,348 $ 18.29 The weighted average grant-date fair value of restricted units granted was $29.02 and $28.70 during the years ended December 31, 2014 and 2013 , respectively. At December 31, 2015 , there was approximately $11.0 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.6 years. Our Consolidated Statements of Operations reflects non-cash compensation related to restricted unit grants of $16.9 million , $10.7 million and $3.4 million in the Selling, general and administrative expenses line item for the years ended December 31, 2015 , 2014 and 2013 , respectively. Phantom Unit Grants As of December 31, 2015 , a summary of the status of the non-vested phantom units under the VNR LTIP is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested units at December 31, 2014 330,321 $ 28.58 Forfeited (2,979 ) $ 28.28 Vested (124,240 ) $ 21.57 Non-vested units at December 31, 2015 203,102 $ 20.99 The weighted average grant-date fair value of phantom units granted was $28.29 during the year ended December 31, 2013 . We did not grant any phantom units during the years ended December 31, 2015 and 2014. At December 31, 2015 , there was approximately $2.3 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.2 years. Compensation expense related to phantom units granted to executive officers, board members and employees of $1.7 million , $1.0 million and $2.6 million has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations for the years ended December 31, 2015 , 2014 , and 2013 , respectively. |
Shelf Registration Statements
Shelf Registration Statements | 12 Months Ended |
Dec. 31, 2015 | |
Shelf Registration Statement [Abstract] | |
Shelf Registration Statement | Shelf Registration Statements and Related Offerings Under our currently effective shelf registration statement, as amended (File No. 333-202064), filed with the SEC (the “Shelf Registration Statement”), we have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common units, debt securities and guarantees of debt securities as shall have an aggregate initial offering price not to exceed $500.0 million . In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Shelf Registration Statement. Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement will be determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us. We have also entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units and common units. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units having an aggregate offering price of up to $400.0 million , (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $50.0 million , (iii) our Series B Cumulative Preferred Units having an aggregate offering price of up to $100.0 million or (iv) our Series C Cumulative Preferred Units having an aggregate offering price of up to $75.0 million . The common units and Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the year ended December 31, 2015, total net proceeds received under the equity distribution agreement were approximately $35.5 million , after commissions and fees of $0.6 million , from the sale of 2,430,170 common units. Subsidiary Guarantors We and VNRF, our wholly owned finance subsidiary, may co-issue securities pursuant to our effective shelf registration statement. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer guaranteed debt securities, the guarantees will be full and unconditional and joint and several, and any subsidiaries of Vanguard that do not guarantee the securities will be minor. The guarantees are also subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances: • in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of the Company; • in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition; • if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture; • upon legal defeasance or satisfaction and discharge of the indenture; • upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing; • at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or • upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist. |
Condensed Consolidating Financi
Condensed Consolidating Financial Statements | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Statements | Condensed Consolidating Financial Statements As previously discussed, in connection with the Eagle Rock Merger, VO assumed the Senior Notes due 2019, which are jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of its subsidiaries. VO and all of the subsidiary guarantors are 100% owned by Vanguard. The guarantees are full and unconditional, subject to certain customary release provisions. In accordance with Rule 3-10 of Regulation S-X, promulgated by the Securities and Exchange Commission, presented below are condensed consolidating financial statements as supplemental information. The following condensed consolidating balance sheet at December 31, 2015 , and condensed consolidating statements of operations and cash flows for the year ended December 31, 2015 , present financial information for VO as the issuer and Vanguard as the parent guarantor, each on a stand-alone basis, financial information for all of the subsidiary guarantors on a combined basis, and the consolidation and elimination entries necessary to arrive at the information for Vanguard on a consolidated basis. The financial information may not necessarily be indicative of the financial position or results of operations had VO or the subsidiary guarantors operated as independent entities. Vanguard has prepared the financial information below using the same accounting policies as the consolidated financial statements except for the use by VO and Vanguard of the equity method of accounting to reflect ownership interests in subsidiaries that are eliminated upon consolidation. There are no restrictions on Vanguard’s ability to obtain cash dividends or other distributions of funds from VO or the subsidiary guarantors. Condensed Consolidating Balance Sheet As of December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) ASSETS: Accounts receivable – affiliates $ 1,897,495 $ 102,678 $ 499,685 $ (2,499,858 ) $ — Other current assets — 94,946 263,576 — 358,522 Oil and natural gas properties — 1,612,791 109,185 — 1,721,976 Total other long-term assets 7,449 530,914 90,436 — 628,799 Total assets $ 1,904,944 $ 2,341,329 $ 962,882 $ (2,499,858 ) $ 2,709,297 LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): Accounts payable – affiliates $ — $ 2,499,858 $ 1,757 $ (2,499,858 ) $ 1,757 Investment in subsidiaries 2,211,408 10,826 — (2,222,234 ) $ — Other current liabilities 16,394 165,442 18,415 — 200,251 Other long-term liabilities — 230,149 72,939 — 303,088 Long-term debt 548,439 55,197 1,688,000 — 2,291,636 Members’ equity (deficit) (871,297 ) (620,143 ) (818,229 ) 2,222,234 (87,435 ) Total liabilities and equity $ 1,904,944 $ 2,341,329 $ 962,882 $ (2,499,858 ) $ 2,709,297 Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) Total revenues — 388,206 178,437 — 566,643 Operating expenses — 183,044 4,186 — 187,230 Selling, general and administrative expenses 8,239 17,008 29,829 — 55,076 Depreciation, depletion, amortization and accretion — 240,891 6,228 — 247,119 Impairment of oil and natural gas properties — 1,806,319 35,998 — 1,842,317 Goodwill impairment loss — 71,425 — — 71,425 Income (loss) from operations (8,239 ) (1,930,481 ) 102,196 — (1,836,524 ) Interest expense, net (46,018 ) (375 ) (41,180 ) — (87,573 ) Other non-operating income — 41,644 (721 ) — 40,923 Income (loss) before equity in earnings of subsidiaries (54,257 ) (1,889,212 ) 60,295 — (1,883,174 ) Equity in earnings (loss) of subsidiaries (1,828,917 ) (37,911 ) — 1,866,828 — Net Income (loss) (1,883,174 ) (1,927,123 ) 60,295 1,866,828 (1,883,174 ) Less: Preferred units distributions (26,759 ) — — — (26,759 ) Net income (loss) attributable to Common and Class B unitholders (1,909,933 ) (1,927,123 ) 60,295 1,866,828 (1,909,933 ) Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net cash flows (used in) provided by operating activities 153,323 149,601 67,160 — 370,084 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property, plant and equipment — (219 ) (425 ) — (644 ) Additions to oil and natural gas properties — (111,738 ) (901 ) — (112,639 ) Acquisitions of oil and natural gas properties and derivative contracts — (12,933 ) (37 ) — (12,970 ) Cash transferred in the EROC and LRE Mergers — 0 18,503 — 18,503 Proceeds from sale of oil and natural gas properties — 1,777 — — 1,777 Deposits and prepayments of natural gas and oil properties — (22,171 ) 0 — (22,171 ) Net cash flows provided by (used in) investing activities — (145,284 ) 17,140 — (128,144 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt — 420,000 — 420,000 Repayment of debt (4,317 ) (504,300 ) — (508,617 ) Proceeds from common unit offerings, net 35,544 — — — 35,544 Repurchase of units under the common unit buyback program (2,399 ) — — — (2,399 ) Distributions to Preferred unitholders (26,760 ) — — — (26,760 ) Distributions to Common and Class B unitholders (147,641 ) — — — (147,641 ) Financing fees (12,067 ) — — — (12,067 ) Net cash flows used in financing activities (153,323 ) (4,317 ) (84,300 ) — (241,940 ) Net increase in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period — — — — — |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Event | Subsequent Events Distributions On January 20, 2016 , our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of December 2015 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, that was paid on February 12, 2016 to Vanguard unitholders of record on February 1, 2016 . Also on January 20, 2016 , our board of directors declared a cash distribution for our preferred unitholders attributable to the month of December 2015 of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit to that was paid on February 12, 2016 to Vanguard preferred unitholders of record on February 1, 2016. On February 18, 2016 , our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2016 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, which will be paid on March 15, 2016 to Vanguard unitholders of record on March 1, 2016 . Also on February 18, 2016 , our board of directors declared a cash distribution for our preferred unitholders attributable to the month of January 2016 of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit, which will be paid on March 15, 2016 to Vanguard preferred unitholders of record on March 1, 2016 . On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Debt Exchange On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of their outstanding 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of the Issuers’ exchange offer. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity. |
New Pronouncement Issued But Not Yet Adopted | In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17 Income taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. |
Cash Equivalents | The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. |
Inventory | Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets. |
Oil and Natural Gas Properties | The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and natural gas liquids (“NGLs”) reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (the “12-month average price”), discounted at 10% , plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015 . Such impairment was recognized during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2015 $ 132,610 $3.91 $82.62 Second quarter 2015 $ 733,365 $3.44 $71.51 Third quarter 2015 $ 491,487 $3.11 $59.23 Fourth quarter 2015 $ 484,855 $2.62 $50.20 Total $ 1,842,317 The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2015 were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date of December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisition date) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. |
Goodwill and Other Intangible Assets | We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” 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 on October 1 or whenever indicators of impairment exist using a two-step process. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach based on our quoted common unit price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary. If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. In addition, if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test is performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, we evaluate any adverse qualitative factors. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. As described above, the key inputs used in estimating the fair value of our reporting unit are our common unit price, number of common units outstanding and a control premium. There is no uncertainty associated with our common unit price and number of common units outstanding. The control premium is based on market data of actual control premiums in our industry. Changes in the common unit price, which could result from further significant declines in the prices of oil and natural gas or significant negative reserve adjustments, or changes in market data as it relates to control premiums in the oil and gas extraction industry could change our estimate of the fair value of the reporting unit and could result in a non-cash impairment charge. We performed our annual impairment tests during 2015 , 2014 and 2013 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed interim impairment tests at December 31, 2015 and 2014. As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million . Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional impairment charge. Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2015 , the net carrying value of this contract was $8.1 million . The carrying value is shown as Other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year. |
Asset Retirement Obligations | We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations. |
Revenue Recognition | Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, our revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets. |
Gas Imbalances | The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2015 or 2014 . |
Concentrations of Credit Risk | Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset. At December 31, 2015 and 2014 , the cash and cash equivalents were primarily concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal. |
Use of Estimates | The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. |
Price and Interest Rate Risk Management Activities | We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 3) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2015 , our derivative transactions included the following: • Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty. • Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. • Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity. • Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. • Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years. • Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Put spread options - created when we purchase a put and sell a put simultaneously. • Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the change in the fair value of the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. Gains or losses on derivative contracts that do not qualify for hedge accounting treatment are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations. We have elected not to designate our current portfolio of derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations. Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. |
Income Taxes | The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However, the tax basis of our net assets exceeded the net book basis by $1.3 billion and $187.0 million at December 31, 2015 and 2014 , respectively. Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.2 million as of December 31, 2015 and 2014 and a deferred tax asset of $0.5 million and $0.3 million as of December 31, 2015 and 2014 , respectively. Tax benefits of $0.3 million and $0.6 million and a tax provision of $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2015 , 2014 , and 2013 , respectively, as a component of Selling, general and administrative expenses. The Company’s provision for income taxes also relates to the federal taxes for ERAC and ERAC II and their wholly owned corporations, ERUD and ERUD II, which are subject to federal income taxes (the “C Corporations”). As part of the Eagle Rock Merger, the Company assumed deferred tax liabilities, the largest single component of which is related to federal income taxes of the C Corporations, where the book/tax differences were created by certain acquisitions completed by ERAC and ERAC II prior to the Eagle Rock Merger. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. As of December 31, 2015 , the Company recorded a deferred tax liability of $39.4 million related to these C Corporations, which is included in the other long-term liabilities line item in the Consolidated Balance Sheet. The Company also recorded a net deferred tax asset of $2.2 million from the Eagle Rock Merger related to the book/tax differences in property, plant and equipment and hedging transactions, which is included in the other assets line item in the Consolidated Balance Sheet. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2015 , based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of the deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of impairment of oil and natural gas properties [Table Text Block] | Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2015 $ 132,610 $3.91 $82.62 Second quarter 2015 $ 733,365 $3.44 $71.51 Third quarter 2015 $ 491,487 $3.11 $59.23 Fourth quarter 2015 $ 484,855 $2.62 $50.20 Total $ 1,842,317 |
Schedule of purchasers accounting for 10% or more of the Company's oil, natural gas and NGLs sales | The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales for the years ended December 31: 2015 2014 2013 Mieco, Inc 20% —% —% Anadarko Petroleum Corporation 2% 19% 1% Marathon Oil Company 7% 12% 14% Plains Marketing L.P. 7% 7% 10% |
Acquisitions and Divestiture (T
Acquisitions and Divestiture (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
Pro forma operating results from acquisitions | The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations: Year Ended December 31, 2015 2014 2013 (in thousands, except per unit amounts) (Pro forma) Total revenues $ 804,564 $ 1,430,710 $ 841,576 Net income (loss) attributable to Common and Class B unitholders $ (2,057,879 ) $ (66,405 ) $ 161,329 Net income (loss) attributable to Common and Class B unitholders, per unit: Basic $ (15.83 ) $ (0.53 ) $ 2.19 Diluted $ (15.83 ) $ (0.53 ) $ 2.17 |
Revenues and Excess of Revenues Over Direct Operating Expenses | The table below presents the amounts of revenues and excess of revenues over direct operating expenses included in our 2015 , 2014 and 2013 Consolidated Statements of Operations for our acquisitions. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes. Year Ended December 31, 2015 2014 2013 (in thousands) LRE Acquisition Revenues $ 13,083 $ — $ — Excess of revenues over direct operating expenses $ 6,029 $ — $ — Eagle Rock Acquisition Revenues $ 23,005 $ — $ — Excess of revenues over direct operating expenses $ 15,112 $ — $ — Pinedale Acquisition Revenues $ 84,934 $ 139,908 $ — Excess of revenues over direct operating expenses $ 56,672 $ 107,934 $ — Piceance Acquisition Revenues $ 37,767 $ 22,642 $ — Excess of revenues over direct operating expenses $ 18,427 $ 15,234 $ — All other acquisitions Revenues $ 58,718 $ 76,915 $ 34,820 Excess of revenues over direct operating expenses $ 30,373 $ 50,317 $ 23,160 |
Pinedale Acquisition [Member] | |
Business Acquisition [Line Items] | |
Fair Value of Assets and Liabilities Acquired | In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million , as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 600,123 Inventory 244 Asset retirement obligations (12,404 ) Imbalance liabilities (171 ) Other (125 ) Total fair value of assets and liabilities acquired 587,667 Fair value of consideration transferred 555,553 Gain on acquisition $ 32,114 |
Piceance Acquisition [Member] | |
Business Acquisition [Line Items] | |
Fair Value of Assets and Liabilities Acquired | In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million , as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 521,401 Asset retirement obligations (19,452 ) Imbalance and suspense liabilities (236 ) Total fair value of assets and liabilities acquired 501,713 Fair value of consideration transferred 502,140 Loss on acquisition $ (427 ) |
Series of Individually Immaterial Business Acquisitions [Member] | |
Business Acquisition [Line Items] | |
Fair Value of Assets and Liabilities Acquired | The following presents the values assigned to the net assets acquired in our 2013 acquisitions: Fair value of assets and liabilities acquired: (in thousands) Oil and natural gas properties $ 317,573 Inventory 899 Asset retirement obligations (11,381 ) Oil and natural gas revenue payable and imbalance liabilities (2,843 ) Total fair value of assets and liabilities acquired 304,248 Fair value of consideration transferred 298,657 Gain on acquisition $ 5,591 |
LRE Merger [Member] | |
Business Acquisition [Line Items] | |
Fair Value of Assets and Liabilities Acquired | Consideration Market value of Vanguard’s common units issued to LRE unitholders $ 123,276 Long-term debt assumed 290,000 413,276 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 5,606 Other current liabilities 9,018 Asset retirement obligations 39,595 Amount attributable to liabilities assumed 54,219 Less: fair value of assets acquired Cash 11,532 Trade accounts receivable 6,822 Other current assets 4,172 Oil and natural gas properties 209,463 Derivative assets 78,725 Other assets 267 Amount attributable assets acquired 310,981 Goodwill $ 156,514 |
EROC Merger [Member] | |
Business Acquisition [Line Items] | |
Fair Value of Assets and Liabilities Acquired | Consideration Market value of Vanguard’s common units issued to Eagle Rock unitholders $ 258,282 Long-term debt assumed 156,550 Replacement share-based payment awards attributable to pre-combination services 346 415,178 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 53,255 Other current liabilities 2,206 Derivative liabilities 2,201 Asset retirement obligations 48,633 Deferred tax liability 39,327 Other long-term liabilities 1,244 Amount attributable to liabilities assumed 146,866 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 17,543 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable assets acquired 602,861 Bargain Purchase Gain $ (40,817 ) |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Financing Arrangements | Our financing arrangements consisted of the following: Amount Outstanding December 31, Description Interest Rate Maturity Date 2015 2014 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,688,000 $ 1,360,000 Senior Notes due 2020 7.875% (2) April 1, 2020 550,000 550,000 Senior Notes due 2019 8.375% (3) June 1, 2019 51,120 — Lease Financing Obligations 4.16% (4) August 10, 2020 (4) 24,668 28,986 $ 2,313,788 $ 1,938,986 Less: Unamortized discount on Senior Notes (17,651 ) (1,852 ) Current portion (4,501 ) (4,318 ) Total long-term debt $ 2,291,636 $ 1,932,816 (1) Variable interest rate was 2.90% and 2.17% at December 31, 2015 and 2014 , respectively. (2) Effective interest rate is 8.0% . (3) Effective interest rate is 21.45% . (4) The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021. |
Borrowing Base Utilization Grid | At December 31, 2015 , the applicable margins and other fees increase as the utilization of the borrowing base increases as follows: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% > 25% <50% > 50% <75% > 75% <90% > 90% Eurodollar Loans Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % ABR Loans Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % Commitment Fee Rate 0.50 % 0.50 % 0.375 % 0.375 % 0.375 % Letter of Credit Fee 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % |
Price and Interest Rate Risk 25
Price and Interest Rate Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivative Contracts Covering Anticipated Future Production | At December 31, 2015 , the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps (West Texas Intermediate) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average Fixed Price January 1, 2016 – December 31, 2016 69,996,888 $ 4.43 1,875,531 $ 84.01 906,900 $ 30.31 January 1, 2017 – December 31, 2017 31,112,760 $ 4.33 749,698 $ 85.70 — $ — Fixed-Price Swaps (Light Louisiana Sweet) Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2017 – December 31, 2017 168,000 $ 91.25 Call Options Sold Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2016 – December 31, 2016 622,200 $ 125.00 January 1, 2017 – December 31, 2017 365,000 $ 95.00 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index January 1, 2016 – December 31, 2016 38,430,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2017 – December 31, 2017 10,950,000 $ (0.22 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index January 1, 2016 – December 31, 2016 968,700 $ (1.01 ) WTI Midland and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 219,600 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 716,500 $ (14.26 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMbtu Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 12,810,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 16,425,000 $ 3.92 $ 4.23 $ 3.37 Oil Contract Period Bbls Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 1,061,400 $ 90.00 $ 96.18 $ 73.62 Puts Oil Contract Period Bbls Put Price ($/Bbl) January 1, 2016 – December 31, 2016 366,000 $ 60.00 Put Options Sold Gas Oil Contract Period MMbtu Put Sold ($/MMbtu) Bbls Put Sold ($/Bbl) January 1, 2016 – December 31, 2016 1,830,000 $ 3.00 146,400 $ 50.00 January 1, 2017 – December 31, 2017 1,825,000 3.50 73,000 $ 75.00 Range Bonus Accumulators Oil Contract Period Bbls Bonus Range Ceiling Range Floor January 1, 2016 – December 31, 2016 183,000 $ 4.00 $ 100.00 $ 75.00 |
Interest Rate Derivative Contracts | At December 31, 2015 , the Company had open interest rate derivative contracts as follows (in thousands): Notional Amount Fixed LIBOR Rates Period: January 1, 2016 to December 10, 2016 $ 20,000 2.17 % January 1, 2016 to October 31, 2016 $ 40,000 1.65 % January 1, 2016 to August 5, 2018 $ 30,000 2.25 % January 1, 2016 to August 6, 2016 $ 25,000 1.80 % January 1, 2016 to October 31, 2016 $ 20,000 1.78 % January 1, 2016 to September 23, 2016 $ 75,000 1.15 % January 1, 2016 to March 7, 2016 $ 75,000 1.08 % January 1, 2016 to September 7, 2016 $ 25,000 1.25 % January 1, 2016 to December 31, 2019 $ 175,000 2.32 % January 1, 2016 to February 16, 2017 $ 75,000 1.73 % January 1, 2016 to June 16, 2017 $ 70,000 1.43 % January 1, 2016 to February 16, 2017 $ 75,000 1.73 % Total $ 705,000 |
Fair Value of Derivatives Outstanding | The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 349,281 $ (21,834 ) $ 327,447 Interest rate derivative contracts — (10,400 ) (10,400 ) Total derivative instruments $ 349,281 $ (32,234 ) $ 317,047 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (21,934 ) $ 21,834 $ (100 ) Interest rate derivative contracts (10,656 ) 10,400 (256 ) Total derivative instruments $ (32,590 ) $ 32,234 $ (356 ) December 31, 2014 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts 289,018 (63,321 ) 225,697 Total derivative instruments $ 289,018 $ (63,321 ) $ 225,697 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (63,615 ) $ 63,321 $ (294 ) Interest rate derivative contracts (4,669 ) — (4,669 ) Total derivative instruments $ (68,284 ) $ 63,321 $ (4,963 ) |
Reported Gains and Losses on Derivative Instruments | The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2015 , 2014 and 2013 is as follows: 2015 2014 2013 (in thousands) Derivative asset at January 1, net $ 220,734 $ 66,711 $ 82,568 Purchases Fair value of derivatives acquired 195,273 (1,344 ) — Premiums and fees paid or deferred for derivative contracts during the period 7,126 — — Net gains on commodity and interest rate derivative contracts 169,569 161,519 11,160 Settlements Net cash settlements received on matured commodity derivative contracts (211,723 ) (10,187 ) (30,905 ) Net cash settlements paid on matured interest rate derivative contracts 5,227 4,035 3,888 Termination of derivative contracts (69,515 ) — — Derivative asset at December 31, net $ 316,691 $ 220,734 $ 66,711 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis | Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): December 31, 2015 Fair Value Measurements Using Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 (in thousands) Assets: Commodity price derivative contracts $ — $ 333,380 $ (5,933 ) $ 327,447 Interest rate derivative contracts — (10,400 ) — (10,400 ) Total derivative instruments $ — $ 322,980 $ (5,933 ) $ 317,047 Liabilities: Commodity price derivative contracts $ — $ (99 ) $ — $ (99 ) Interest rate derivative contracts — (257 ) — (257 ) Total derivative instruments $ — $ (356 ) $ — $ (356 ) December 31, 2014 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value (in thousands) Assets: Commodity price derivative contracts $ — $ 232,167 $ (6,470 ) $ 225,697 Total derivative instruments $ — $ 232,167 $ (6,470 ) $ 225,697 Liabilities: Commodity price derivative contracts $ — $ (294 ) $ — $ (294 ) Interest rate derivative contracts — (4,669 ) — (4,669 ) Total derivative instruments $ — $ (4,963 ) $ — $ (4,963 ) |
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: 2015 2014 (in thousands) Unobservable inputs at January 1, $ (6,470 ) $ 566 Total gains (losses) 5,151 (8,238 ) Settlements (4,614 ) 1,202 Unobservable inputs at December 31, $ (5,933 ) $ (6,470 ) Change in fair value included in earnings related to derivatives still held as of December 31, $ (2,925 ) $ (6,326 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Changes in Asset Retirement Obligations | The asset retirement obligations as of December 31 , reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31 , were as follows: 2015 2014 (in thousands) Asset retirement obligation at January 1, $ 149,062 $ 87,967 Liabilities added during the current period 2,699 52,829 Liabilities added from the LRE and Eagle Rock Mergers 88,228 — Accretion expense 10,238 5,889 Change in estimate 22,329 4,118 Disposition of properties (262 ) (1,291 ) Retirements (838 ) (450 ) Total asset retirement obligation at December 31, 271,456 149,062 Less: current obligations (9,024 ) (2,386 ) Long-term asset retirement obligation at December 31, $ 262,432 $ 146,676 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of gross future minimum transportation demand | The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2015 . However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. (in thousands) 2016 $ 14,957 2017 12,512 2018 11,696 2019 9,661 2020 410 Thereafter — Total $ 49,236 |
Members' Equity (Deficit) and29
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Cumulative Preferred Units | The following table summarizes the Company’s Cumulative Preferred Units outstanding at December 31, 2015 and 2014 : 2015 2014 Earliest Redemption Date Liquidation Preference Per Share Distribution Rate Units Outstanding Carrying Value Units Outstanding Carrying Value Series A June 15, 2023 $25.00 7.875% 2,581,873 $ 62,200 2,581,873 $ 62,200 Series B April 15, 2024 $25.00 7.625% 7,000,000 $ 169,265 7,000,000 $ 169,265 Series C October 15, 2024 $25.00 7.75% 4,300,000 $ 103,979 4,300,000 $ 103,979 Total Cumulative Preferred Units 13,881,873 $ 335,444 13,881,873 $ 335,444 |
Common and Class B Units outstanding | The following is a summary of the changes in our common units issued during the years ended December 31, 2015 , 2014 and 2013 (in thousands): 2015 2014 2013 Beginning of period 83,452 78,337 58,706 Issuance of Common units as consideration for the Eagle Rock Merger 27,886 — — Issuance of Common units as consideration for the LRE Merger 15,448 — — Issuance of Common units for the acquisition of oil and natural gas properties — — 1,075 Issuance of Common units for cash 2,430 4,864 18,377 Repurchase of units under the common unit buyback program (157 ) (135 ) — Unit-based compensation 1,418 386 179 End of period 130,477 83,452 78,337 |
Schedule of Earnings per unit, basic and diluted | The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows (in thousands, except per unit data): 2015 (a) 2014 2013 Net income (loss) attributable to Common and Class B unitholders $ (1,909,933 ) $ 46,148 $ 56,877 Weighted average number of Common and Class B units outstanding - basic 96,468 82,031 73,064 Effect of dilutive securities: Phantom units — 428 348 Weighted average number of Common and Class B units outstanding - diluted 96,468 82,459 73,412 Net income (loss) per Common and Class B unit Basic $ (19.80 ) $ 0.56 $ 0.78 Diluted $ (19.80 ) $ 0.55 $ 0.77 |
Distributions Declared | The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2015 Fourth Quarter November $ 0.0300 December 18, 2015 January 4, 2016 January 14, 2016 October $ 0.1175 November 20, 2015 December 1, 2015 December 15, 2015 Third Quarter September $ 0.1175 October 19, 2015 November 2, 2015 November 13, 2015 August $ 0.1175 September 21, 2015 October 1, 2015 October 15, 2015 July $ 0.1175 August 20, 2015 September 1, 2015 September 14, 2015 Second Quarter June $ 0.1175 July 16, 2015 August 3, 2015 August 14, 2015 May $ 0.1175 June 18, 2015 July 1, 2015 July 15, 2015 April $ 0.1175 May 19, 2015 June 1, 2015 June 12, 2015 First Quarter March $ 0.1175 April 15, 2015 May 1, 2015 May 15, 2015 February $ 0.1175 March 18, 2015 April 1, 2015 April 14, 2015 January $ 0.1175 February 17, 2015 March 2, 2015 March 17, 2015 2014 Fourth Quarter December $ 0.2100 January 22, 2015 February 2, 2015 February 13, 2015 November $ 0.2100 December 16, 2014 January 2, 2015 January 14, 2015 October $ 0.2100 November 20, 2014 December 1, 2014 December 15, 2014 Third Quarter September $ 0.2100 October 20, 2014 November 3, 2014 November 14, 2014 August $ 0.2100 September 19, 2014 October 1, 2014 October 15, 2014 July $ 0.2100 August 19, 2014 September 2, 2014 September 12, 2014 Second Quarter June $ 0.2100 July 16, 2014 August 1, 2014 August 14, 2014 May $ 0.2100 June 24, 2014 July 1, 2014 July 15, 2014 April $ 0.2100 May 20, 2014 June 2, 2014 June 13, 2014 First Quarter March $ 0.2100 April 17, 2014 May 1, 2014 May 15, 2014 February $ 0.2100 March 17, 2014 April 1, 2014 April 14, 2014 January $ 0.2075 February 2, 2014 March 3, 2014 March 17, 2014 2013 Fourth Quarter December $ 0.2075 January 16, 2014 February 3, 2014 February 14, 2014 November $ 0.2075 December 17, 2013 January 2, 2014 January 15, 2014 October $ 0.2075 November 19, 2013 December 2, 2013 December 13, 2013 Third Quarter September $ 0.2075 October 21, 2013 November 1, 2013 November 14, 2013 August $ 0.2075 September 12, 2013 October 1, 2013 October 15, 2013 July $ 0.2075 August 20, 2013 September 3, 2013 September 13, 2013 Second Quarter June $ 0.2050 July 18, 2013 August 1, 2013 August 14, 2013 May $ 0.2050 June 20, 2013 July 1, 2013 July 15, 2013 April $ 0.2050 April 30, 2013 June 3, 2013 June 14, 2013 First Quarter March $ 0.2025 April 19, 2013 May 1, 2013 May 15, 2013 February $ 0.2025 March 21, 2013 April 1, 2013 April 12, 2013 January $ 0.2025 February 18, 2013 March 1, 2013 March 15, 2013 2012 Fourth Quarter December $ 0.2025 January 25, 2013 February 4, 2013 February 14, 2013 |
Unit-Based Compensation Unit-Ba
Unit-Based Compensation Unit-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Nonvested Restricted Units Activity [Table Text Block] | As of December 31, 2015 , a summary of the status of the non-vested restricted units under the VNR LTIP is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested units at December 31, 2014 440,047 $ 28.87 Granted 562,393 $ 15.17 Forfeited (17,670 ) $ 20.54 Non-vested Eagle Rock LTIP units replaced with VNR LTIP restricted units 143,647 $ 9.01 Vested (152,069 ) $ 26.04 Non-vested units at December 31, 2015 976,348 $ 18.29 |
Schedule of Nonvested Phantom Units, Activity [Table Text Block] | As of December 31, 2015 , a summary of the status of the non-vested phantom units under the VNR LTIP is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested units at December 31, 2014 330,321 $ 28.58 Forfeited (2,979 ) $ 28.28 Vested (124,240 ) $ 21.57 Non-vested units at December 31, 2015 203,102 $ 20.99 |
Condensed Consolidating Finan31
Condensed Consolidating Financial Statements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Balance Sheet | Condensed Consolidating Balance Sheet As of December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) ASSETS: Accounts receivable – affiliates $ 1,897,495 $ 102,678 $ 499,685 $ (2,499,858 ) $ — Other current assets — 94,946 263,576 — 358,522 Oil and natural gas properties — 1,612,791 109,185 — 1,721,976 Total other long-term assets 7,449 530,914 90,436 — 628,799 Total assets $ 1,904,944 $ 2,341,329 $ 962,882 $ (2,499,858 ) $ 2,709,297 LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): Accounts payable – affiliates $ — $ 2,499,858 $ 1,757 $ (2,499,858 ) $ 1,757 Investment in subsidiaries 2,211,408 10,826 — (2,222,234 ) $ — Other current liabilities 16,394 165,442 18,415 — 200,251 Other long-term liabilities — 230,149 72,939 — 303,088 Long-term debt 548,439 55,197 1,688,000 — 2,291,636 Members’ equity (deficit) (871,297 ) (620,143 ) (818,229 ) 2,222,234 (87,435 ) Total liabilities and equity $ 1,904,944 $ 2,341,329 $ 962,882 $ (2,499,858 ) $ 2,709,297 |
Condensed Income Statement | Condensed Consolidating Statement of Operations For the Year Ended December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) Total revenues — 388,206 178,437 — 566,643 Operating expenses — 183,044 4,186 — 187,230 Selling, general and administrative expenses 8,239 17,008 29,829 — 55,076 Depreciation, depletion, amortization and accretion — 240,891 6,228 — 247,119 Impairment of oil and natural gas properties — 1,806,319 35,998 — 1,842,317 Goodwill impairment loss — 71,425 — — 71,425 Income (loss) from operations (8,239 ) (1,930,481 ) 102,196 — (1,836,524 ) Interest expense, net (46,018 ) (375 ) (41,180 ) — (87,573 ) Other non-operating income — 41,644 (721 ) — 40,923 Income (loss) before equity in earnings of subsidiaries (54,257 ) (1,889,212 ) 60,295 — (1,883,174 ) Equity in earnings (loss) of subsidiaries (1,828,917 ) (37,911 ) — 1,866,828 — Net Income (loss) (1,883,174 ) (1,927,123 ) 60,295 1,866,828 (1,883,174 ) Less: Preferred units distributions (26,759 ) — — — (26,759 ) Net income (loss) attributable to Common and Class B unitholders (1,909,933 ) (1,927,123 ) 60,295 1,866,828 (1,909,933 ) |
Condensed Cash Flow Statement | Condensed Consolidating Statement of Cash Flows For the Year Ended December 31, 2015 Parent Issuer Guarantors Consolidating Entries Total ($ in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net cash flows (used in) provided by operating activities 153,323 149,601 67,160 — 370,084 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property, plant and equipment — (219 ) (425 ) — (644 ) Additions to oil and natural gas properties — (111,738 ) (901 ) — (112,639 ) Acquisitions of oil and natural gas properties and derivative contracts — (12,933 ) (37 ) — (12,970 ) Cash transferred in the EROC and LRE Mergers — 0 18,503 — 18,503 Proceeds from sale of oil and natural gas properties — 1,777 — — 1,777 Deposits and prepayments of natural gas and oil properties — (22,171 ) 0 — (22,171 ) Net cash flows provided by (used in) investing activities — (145,284 ) 17,140 — (128,144 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt — 420,000 — 420,000 Repayment of debt (4,317 ) (504,300 ) — (508,617 ) Proceeds from common unit offerings, net 35,544 — — — 35,544 Repurchase of units under the common unit buyback program (2,399 ) — — — (2,399 ) Distributions to Preferred unitholders (26,760 ) — — — (26,760 ) Distributions to Common and Class B unitholders (147,641 ) — — — (147,641 ) Financing fees (12,067 ) — — — (12,067 ) Net cash flows used in financing activities (153,323 ) (4,317 ) (84,300 ) — (241,940 ) Net increase in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — — — — — Cash and cash equivalents at end of period — — — — — |
Description of the Business (De
Description of the Business (Details) | 12 Months Ended |
Dec. 31, 2015operating_areas | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating areas | 10 |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Oil and Natural Gas Properties) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2015USD ($)$ / bbl$ / MMBTU | Sep. 30, 2015USD ($)$ / bbl$ / MMBTU | Jun. 30, 2015USD ($)$ / bbl$ / MMBTU | Mar. 31, 2015USD ($)$ / bbl$ / MMBTU | Dec. 31, 2014$ / bbl$ / MMBTU | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||
Discount rate used in determining limitation of capitalized costs | 10.00% | |||||||
Impairment of oil and natural gas properties | $ | $ 484,855 | $ 491,487 | $ 733,365 | $ 132,610 | $ 1,842,317 | $ 234,434 | $ 0 | |
Average price of natural gas used in the impairment calculation | $ / MMBTU | 2.62 | 3.11 | 3.44 | 3.91 | 4.36 | |||
Average price of crude oil used in the impairment calculation (per barrel) | $ / bbl | 50.20 | 59.23 | 71.51 | 82.62 | 94.87 |
Summary of Significant Accoun34
Summary of Significant Accounting Policies (Other Intangible Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Intangible Assets | |||
Goodwill impairment loss | $ 71,425 | $ 0 | $ 0 |
Goodwill | 506,046 | $ 420,955 | |
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 0.00% | ||
Contract [Member] | |||
Estimated aggregate amortization expense for each of the next five fiscal years | |||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 200 | ||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 200 | ||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 200 | ||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 200 | ||
Finite-Lived Intangible Assets, Amortization Expense, Year Five | 200 | ||
Contract [Member] | Other assets [Member] | |||
Other Intangible Assets | |||
Net carrying value of contract | $ 8,100 |
Summary of Significant Accoun35
Summary of Significant Accounting Policies (Concentrations of Credit Risk) (Details) - institution | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenue, Major Purchasers | |||
Concentration Risk, Number of Financial Institutions | 1 | 1 | |
Customer Concentration Risk [Member] | Sales [Member] | Mieco, Inc. [Member] | |||
Revenue, Major Purchasers | |||
Major purchasers, percent of sales | 20.00% | 0.00% | 0.00% |
Customer Concentration Risk [Member] | Sales [Member] | Anadarko Petroleum Corporation [Member] | |||
Revenue, Major Purchasers | |||
Major purchasers, percent of sales | 2.00% | 19.00% | 1.00% |
Customer Concentration Risk [Member] | Sales [Member] | Marathon Oil Company [Member] | |||
Revenue, Major Purchasers | |||
Major purchasers, percent of sales | 7.00% | 12.00% | 14.00% |
Customer Concentration Risk [Member] | Sales [Member] | Plains Marketing L.P. [Member] | |||
Revenue, Major Purchasers | |||
Major purchasers, percent of sales | 7.00% | 7.00% | 10.00% |
Summary of Significant Accoun36
Summary of Significant Accounting Policies (Income Taxes) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revised Texas Franchise Tax | |||
Entity Not Subject to Income Taxes, Differences in Bases, Amount | $ 1,300 | $ 187 | |
Deferred Tax Assets, Net | 2.2 | ||
Deferred Tax Liabilities, Other | 39.4 | ||
Texas [Member] | |||
Revised Texas Franchise Tax | |||
Current tax liability | (0.2) | (0.2) | |
Deferred tax asset | 0.5 | 0.3 | |
Income Tax Expense (Benefit) | $ (0.3) | $ 0.6 | $ 0.6 |
Acquisitions and Divestiture Ac
Acquisitions and Divestiture Acquisitions (LRE Merger) (Details) $ / shares in Units, $ in Thousands, shares in Millions | Oct. 08, 2015USD ($)$ / sharesshares | Oct. 05, 2015USD ($)$ / sharesshares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Less: fair value of assets acquired | ||||
Goodwill | $ 506,046 | $ 420,955 | ||
LRE Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio | 0.550 | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 15.4 | |||
Business Acquisition, Share Price | $ / shares | $ 7.98 | |||
Business Combination, Consideration Transferred [Abstract] | ||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $ 123,276 | |||
Long-term debt assumed | 290,000 | |||
Business Combination, Consideration Transferred | 413,276 | |||
Add: fair value of liabilities assumed | ||||
Accounts payable and accrued liabilities | 5,606 | |||
Other current liabilities | 9,018 | |||
Asset retirement obligations | 39,595 | |||
Amount attributable to liabilities assumed | 54,219 | |||
Less: fair value of assets acquired | ||||
Cash | 11,532 | |||
Trade accounts receivable | 6,822 | |||
Other current assets | 4,172 | |||
Oil and natural gas properties | 209,463 | |||
Derivative assets | 78,725 | |||
Other assets | 267 | |||
Amount attributable assets acquired | 310,981 | |||
Goodwill | $ 156,514 | |||
EROC Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio | 0.185 | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 27.7 | |||
Business Acquisition, Share Price | $ / shares | $ 9.31 | |||
Business Combination, Consideration Transferred [Abstract] | ||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $ 258,282 | |||
Long-term debt assumed | 156,550 | |||
Business Combination, Consideration Transferred | 415,178 | |||
Add: fair value of liabilities assumed | ||||
Accounts payable and accrued liabilities | 53,255 | |||
Other current liabilities | 2,206 | |||
Asset retirement obligations | 48,633 | |||
Amount attributable to liabilities assumed | 146,866 | |||
Less: fair value of assets acquired | ||||
Cash | 6,971 | |||
Trade accounts receivable | 17,543 | |||
Other current assets | 15,664 | |||
Oil and natural gas properties | 462,715 | |||
Derivative assets | 90,234 | |||
Other assets | 9,734 | |||
Amount attributable assets acquired | $ 602,861 | |||
General Partner [Member] | LRE Merger [Member] | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 0 |
Acquisitions and Divestiture 38
Acquisitions and Divestiture Acquisitions (Eagle Rock Merger) (Details) | Oct. 08, 2015USD ($)$ / shares | Dec. 31, 2015USD ($) |
Business Combination, Consideration Transferred [Abstract] | ||
Replacement share-based payment awards attributable to pre-combination services | $ 143,647 | |
EROC Merger [Member] | ||
Business Acquisition [Line Items] | ||
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio | 0.185 | |
Market value of Vanguard’s common units issued to Eagle Rock unitholders | $ 258,282,000 | |
Business Acquisition, Share Price | $ / shares | $ 9.31 | |
Debt extinguished subsequent to the merger | $ 122,300,000 | |
Business Combination, Consideration Transferred [Abstract] | ||
Long-term debt assumed | 156,550,000 | |
Replacement share-based payment awards attributable to pre-combination services | 346,000 | |
Business Combination, Consideration Transferred | 415,178,000 | |
Amount attributable to liabilities assumed | ||
Accounts payable and accrued liabilities | 53,255,000 | |
Other current liabilities | 2,206,000 | |
Derivative liabilities | 2,201,000 | |
Asset retirement obligations | 48,633,000 | |
Deferred tax liability | 39,327,000 | |
Other long-term liabilities | 1,244,000 | |
Amount attributable to liabilities assumed | 146,866,000 | |
Less: fair value of assets acquired | ||
Cash | 6,971,000 | |
Trade accounts receivable | 17,543,000 | |
Other current assets | 15,664,000 | |
Oil and natural gas properties | 462,715,000 | |
Derivative assets | 90,234,000 | |
Other assets | 9,734,000 | |
Amount attributable assets acquired | 602,861,000 | |
Bargain Purchase Gain | $ (40,817,000) |
Acquisitions and Divestiture (D
Acquisitions and Divestiture (Details) - USD ($) $ / shares in Units, $ in Thousands | Oct. 05, 2015 | Jul. 31, 2015 | Sep. 30, 2014 | Aug. 29, 2014 | May. 02, 2014 | Jan. 31, 2014 | Jun. 28, 2013 | Apr. 02, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Business Acquisition [Line Items] | |||||||||||
Goodwill | $ 506,046 | $ 420,955 | |||||||||
Pinedale Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 555,553 | ||||||||||
Gain on acquisition | $ 32,114 | ||||||||||
Effective date of acquisition | Oct. 1, 2013 | ||||||||||
Piceance Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 502,140 | ||||||||||
Goodwill | $ 427 | ||||||||||
Wamsutter Property Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 6,800 | ||||||||||
Effective date of acquisition | Jan. 1, 2014 | ||||||||||
Ownership interest conveyed | 75.00% | ||||||||||
Gulf Coast Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 269,900 | ||||||||||
Effective date of acquisition | Jun. 1, 2014 | ||||||||||
Series of Individually Immaterial Business Acquisitions [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 11,400 | $ 266,200 | $ 17,700 | $ 298,657 | |||||||
Gain on acquisition | $ 5,591 | ||||||||||
Effective date of acquisition | Jul. 1, 2013 | Jan. 1, 2013 | |||||||||
Purchase price of acquired entity paid in common equity | $ 29,900 | ||||||||||
Number of shares issued | 1,075,000 | ||||||||||
Shares issued, agreed share price | $ 27.65 | ||||||||||
Shares issued, closing price | $ 27.90 | ||||||||||
Other smaller acquisitions [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 2,500 | ||||||||||
LRE Merger [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Consideration Transferred | $ 413,276 | ||||||||||
Purchase price of acquired entity paid in common equity | $ 123,276 | ||||||||||
Number of shares issued | 15,400,000 | ||||||||||
Shares issued, closing price | $ 7.98 | ||||||||||
Goodwill | $ 156,514 |
Acquisitions and Divestiture (A
Acquisitions and Divestiture (Aggregate Values Assigned to Net Assets Acquired) (Details) - USD ($) $ in Thousands | Jul. 31, 2015 | Sep. 30, 2014 | Jan. 31, 2014 | Apr. 02, 2013 | Dec. 31, 2015 | Dec. 31, 2013 | Dec. 31, 2014 |
Fair value of assets and liabilities acquired: | |||||||
Loss on acquisition | $ (506,046) | $ (420,955) | |||||
Series of Individually Immaterial Business Acquisitions [Member] | |||||||
Fair value of assets and liabilities acquired: | |||||||
Oil and natural gas properties | $ 317,573 | ||||||
Asset retirement obligations | (11,381) | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory | 899 | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other | (2,843) | ||||||
Total fair value of assets and liabilities acquired | 304,248 | ||||||
Fair value of consideration transferred | $ (11,400) | $ (266,200) | $ (17,700) | (298,657) | |||
Gain on acquisition | $ 5,591 | ||||||
Piceance Acquisition [Member] | |||||||
Fair value of assets and liabilities acquired: | |||||||
Oil and natural gas properties | $ 521,401 | ||||||
Asset retirement obligations | (19,452) | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other | (236) | ||||||
Total fair value of assets and liabilities acquired | 501,713 | ||||||
Fair value of consideration transferred | (502,140) | ||||||
Loss on acquisition | $ (427) | ||||||
Pinedale Acquisition [Member] | |||||||
Fair value of assets and liabilities acquired: | |||||||
Oil and natural gas properties | $ 600,123 | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable | (125) | ||||||
Asset retirement obligations | (12,404) | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory | 244 | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other | (171) | ||||||
Total fair value of assets and liabilities acquired | 587,667 | ||||||
Fair value of consideration transferred | (555,553) | ||||||
Gain on acquisition | $ 32,114 |
Acquisitions and Divestiture (P
Acquisitions and Divestiture (Pro Forma) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pro Forma Information | |||
Total revenues | $ 804,564 | $ 1,430,710 | $ 841,576 |
Net income (loss) | $ (2,057,879) | $ (66,405) | $ 161,329 |
Net income (loss) attributable to Common and Class B unitholders, per unit: | |||
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ (15.83) | $ (0.53) | $ 2.19 |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ (15.83) | $ (0.53) | $ 2.17 |
Acquisitions and Divestiture 42
Acquisitions and Divestiture (Acquiree Earnings) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
LRE Merger [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | $ 13,083 | ||
Excess of revenues over direct operating expenses | 6,029 | ||
EROC Merger [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 23,005 | ||
Excess of revenues over direct operating expenses | 15,112 | ||
Pinedale Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 84,934 | $ 139,908 | $ 0 |
Excess of revenues over direct operating expenses | 56,672 | 107,934 | 0 |
Piceance Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 37,767 | 22,642 | 0 |
Excess of revenues over direct operating expenses | 18,427 | 15,234 | 0 |
Series of Individually Immaterial Business Acquisitions [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 58,718 | 76,915 | 34,820 |
Excess of revenues over direct operating expenses | $ 30,373 | $ 50,317 | $ 23,160 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) | Feb. 10, 2016 | Dec. 31, 2015 | Jan. 01, 2017 | Jan. 01, 2016 | Nov. 06, 2015 | Nov. 03, 2015 | Oct. 08, 2015 | Jun. 03, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Covenant, Debt to EBITDA ratio | 550.00% | 550.00% | |||||||
Debt amount outstanding | $ 2,313,788,000 | $ 1,938,986,000 | |||||||
Long-term Debt | 2,291,636,000 | 1,932,816,000 | |||||||
Debt covenant, maximum investment in certain entities | $ 100,000,000 | $ 5,000,000 | |||||||
Debt covenant, Reduction in borrowing capacity | 25.00% | ||||||||
Purchase of equipment at early buyout date | $ 16,000,000 | ||||||||
Senior Notes [Abstract] | |||||||||
Percentage of ownership (in hundredths) | 100.00% | ||||||||
Line of Credit [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Maximum facility size | $ 3,500,000,000 | ||||||||
Borrowing base | $ 1,800,000,000 | ||||||||
Maturity date | Apr. 16, 2018 | ||||||||
Debt amount outstanding | $ 1,688,000,000 | 1,360,000,000 | |||||||
Remaining borrowing capacity | 107,500,000 | ||||||||
Senior Notes [Abstract] | |||||||||
Authorized distribution to unitholders | 23,000,000 | ||||||||
Line of Credit [Member] | Standby Letters of Credit [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Borrowing base | $ 4,500,000 | ||||||||
Capital Lease Obligations [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Maturity date | Aug. 10, 2020 | ||||||||
Debt amount outstanding | $ 24,668,000 | 28,986,000 | |||||||
Senior Notes [Abstract] | |||||||||
Stated interest rate (in hundredths) | 4.16% | ||||||||
Senior Notes due 2020 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | 8.00% | ||||||||
Maturity date | Apr. 1, 2020 | ||||||||
Debt amount outstanding | $ 550,000,000 | $ 550,000,000 | |||||||
Senior Notes [Abstract] | |||||||||
Stated interest rate (in hundredths) | 7.875% | ||||||||
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths) | 103.9375% | ||||||||
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths) | 100.00% | ||||||||
Redemption price of aggregate principal amount of senior notes at any time prior to April 1, 2016 (in hundredths) | 100.00% | ||||||||
Required repurchase price of aggregate principal amount of senior notes, lower range (in hundredths) | 100.00% | ||||||||
Required repurchase price of aggregate principal amount of senior notes, upper range (in hundredths) | 101.00% | ||||||||
Subordinated Debt [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Maximum facility size | $ 300,000,000 | ||||||||
Senior Notes due 2019 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | 21.45% | ||||||||
Maturity date | Jun. 1, 2019 | ||||||||
Debt amount outstanding | $ 51,120,000 | $ 51,100,000 | |||||||
Long-term Debt | $ 34,300,000 | ||||||||
Senior Notes [Abstract] | |||||||||
Stated interest rate (in hundredths) | 8.375% | ||||||||
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths) | 102.094% | ||||||||
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths) | 100.00% | ||||||||
Scenario, Forecast [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Covenant, Debt to EBITDA ratio | 450.00% | 525.00% | |||||||
Senior Notes [Abstract] | |||||||||
Extinguishment of Debt, Amount | $ 168,200,000 | ||||||||
Subsequent Event [Member] | Subordinated Debt [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt amount outstanding | $ 75,600,000 | ||||||||
Senior Notes [Abstract] | |||||||||
Stated interest rate (in hundredths) | 7.00% | ||||||||
Extinguishment of Debt, Amount | $ 168,200,000 |
Long-Term Debt (Financing Arran
Long-Term Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||
Debt amount outstanding | $ 2,313,788 | $ 1,938,986 |
Unamortized discount on Senior Notes | (17,651) | (1,852) |
Short-term Debt | (4,501) | (4,318) |
Total long-term debt | $ 2,291,636 | 1,932,816 |
Line of Credit [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate description | Variable (1) | |
Maturity date | Apr. 16, 2018 | |
Debt amount outstanding | $ 1,688,000 | $ 1,360,000 |
Variable interest rate (in hundredths) | 2.90% | 2.17% |
Capital Lease Obligations [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate (in hundredths) | 4.16% | |
Maturity date | Aug. 10, 2020 | |
Debt amount outstanding | $ 24,668 | $ 28,986 |
Long-Term Debt (Borrowing Base
Long-Term Debt (Borrowing Base Utilization Grid) (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Borrowing Base Utilization Less Than 25% [Member] | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.50% |
Letter of credit fee (in hundredths) | 0.50% |
Borrowing Base Utilization Less Than 25% [Member] | Eurodollar Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.50% |
Borrowing Base Utilization Less Than 25% [Member] | ABR Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 0.50% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.50% |
Letter of credit fee (in hundredths) | 0.75% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | Eurodollar Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.75% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | ABR Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 0.75% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.00% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | Eurodollar Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.00% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | ABR Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.00% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.25% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | Eurodollar Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.25% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | ABR Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.25% |
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.50% |
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | Eurodollar Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.50% |
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | ABR Loans Margin [Member] | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.50% |
Price and Interest Rate Risk 46
Price and Interest Rate Risk Management Activities (Derivative Contracts Covering Aniticipated Future Production) (Details) | 12 Months Ended |
Dec. 31, 2015MMBTU$ / bbl$ / MMBTUbbl | |
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 84.01 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,875,531 |
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 85.70 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 749,698 |
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 69,996,888 |
Weighted average price of derivative (in dollars per unit) | $ / MMBTU | 4.43 |
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 31,112,760 |
Weighted average price of derivative (in dollars per unit) | $ / MMBTU | 4.33 |
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 30.31 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 906,900 |
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 0 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 0 |
Call Option [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 125 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 622,200 |
Call Option [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Weighted average price of derivative (in dollars per unit) | 95 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 365,000 |
Three-Way Collars [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Floor (in dollars per unit) | 90 |
Ceiling (in dollars per unit) | 96.18 |
Derivative, Average Price Risk Option Strike Price | 73.62 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,061,400 |
Three-Way Collars [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 12,810,000 |
Floor (in dollars per unit) | $ / MMBTU | 3.95 |
Ceiling (in dollars per unit) | $ / MMBTU | 4.25 |
Derivative, Average Price Risk Option Strike Price | $ / MMBTU | 3 |
Three-Way Collars [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 16,425,000 |
Floor (in dollars per unit) | $ / MMBTU | 3.92 |
Ceiling (in dollars per unit) | $ / MMBTU | 4.23 |
Derivative, Average Price Risk Option Strike Price | $ / MMBTU | 3.37 |
Puts [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 366,000 |
Derivative, Price Risk Option Strike Price | 60 |
Put Option Sold [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Average Price Risk Option Strike Price | 50 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 146,400 |
Put Option Sold [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Derivative, Average Price Risk Option Strike Price | 75 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 73,000 |
Put Option Sold [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Notional Volume (Bbls) | MMBTU | 1,830,000 |
Derivative, Average Price Risk Option Strike Price | $ / MMBTU | 3 |
Put Option Sold [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Notional Volume (Bbls) | MMBTU | 1,825,000 |
Derivative, Average Price Risk Option Strike Price | $ / MMBTU | 3.50 |
Range Bonus Accumulators [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | bbl | 183,000 |
Bonus (in dollars per unit) | 4 |
Derivative, Average Cap Price | 100 |
Derivative, Average Floor Price | 75 |
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 38,430,000 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.20) |
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member] | |
Derivative [Line Items] | |
Anticipated future gas production (in units) | MMBTU | 10,950,000 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.22) |
Midland-Cushing Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Weighted average basis differential (in dollars per unit) | (1.01) |
Portion of Future Oil and Gas Production Being Hedged | bbl | 968,700 |
Midland-WTS Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member] | |
Derivative [Line Items] | |
Weighted average basis differential (in dollars per unit) | (0.43) |
Portion of Future Oil and Gas Production Being Hedged | bbl | 219,600 |
WTI-WCS Index [Member] | Basis Swaps [Member] | Oil [Member] | Contract period October 1, 2015 to December 31, 2015 [Member] | |
Derivative [Line Items] | |
Weighted average basis differential (in dollars per unit) | 14.26 |
Portion of Future Oil and Gas Production Being Hedged | bbl | 716,500 |
Price and Interest Rate Risk 47
Price and Interest Rate Risk Management Activities (Interest Rate Swaps) (Details) - Interest rate swaps [Member] $ in Thousands | Dec. 31, 2015USD ($) |
Derivative [Line Items] | |
Notional amount | $ 705,000 |
Contract period January 1, 2016 to December 10, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 20,000 |
Fixed Libor Rates (in hundredths) | 2.17% |
Contract period January 1, 2016 to October 31, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 40,000 |
Fixed Libor Rates (in hundredths) | 1.65% |
Contract period January 1, 2016 to August 5, 2018 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 30,000 |
Fixed Libor Rates (in hundredths) | 2.25% |
Contract period January 1, 2016 to August 6, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 25,000 |
Fixed Libor Rates (in hundredths) | 1.80% |
Contract period January 1, 2016 to October 31, 2016 swap B [Member] | |
Derivative [Line Items] | |
Notional amount | $ 20,000 |
Fixed Libor Rates (in hundredths) | 1.78% |
Contract period January 1, 2016 to September 23, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.149% |
Contract period January 1, 2016 to March 7, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.08% |
Contract period January 1, 2016 to September 7, 2016 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 25,000 |
Fixed Libor Rates (in hundredths) | 1.25% |
Contract period January 1, 2016 to December 31, 2019 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 175,000 |
Fixed Libor Rates (in hundredths) | 2.3195% |
Contract period January 1, 2016 to February 16, 2017 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.7275% |
Contract period January 1, 2016 to June 16, 2017 [Member] | |
Derivative [Line Items] | |
Notional amount | $ 70,000 |
Fixed Libor Rates (in hundredths) | 1.4275% |
Contract period January 1, 2016 to February 16, 2017 swap B [Member] | |
Derivative [Line Items] | |
Notional amount | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.725% |
Price and Interest Rate Risk 48
Price and Interest Rate Risk Management Activities (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 349,281 | $ 289,018 |
Derivative Asset, Fair Value, Gross Liability | (32,234) | (63,321) |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 317,047 | 225,697 |
Derivative Liability, Fair Value, Gross Liability | (32,590) | (68,284) |
Derivative Liability, Fair Value, Gross Asset | 32,234 | 63,321 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (356) | (4,963) |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 349,281 | 289,018 |
Derivative Asset, Fair Value, Gross Liability | (21,834) | (63,321) |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 327,447 | 225,697 |
Derivative Liability, Fair Value, Gross Liability | (21,934) | (63,615) |
Derivative Liability, Fair Value, Gross Asset | 21,834 | 63,321 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (100) | (294) |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | |
Derivative Asset, Fair Value, Gross Liability | (10,400) | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (10,400) | |
Derivative Liability, Fair Value, Gross Liability | (10,656) | (4,669) |
Derivative Liability, Fair Value, Gross Asset | 10,400 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ (256) | $ (4,669) |
Price and Interest Rate Risk 49
Price and Interest Rate Risk Management Activities Price and Interest Rate Risk Management Activities (Additional Disclosures) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Maximum potential loss due to credit risk | $ 349.3 |
Price and Interest Rate Risk 50
Price and Interest Rate Risk Management Activities Price and Interest Rate Risk Management Activities (Change in Fair Value of Derivatives) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | |||
Derivative asset/(liability) at beginning of year, net | $ 220,734 | $ 66,711 | $ 82,568 |
Fair value of derivative contracts acquired through business combinations | 195,273 | (1,344) | 0 |
Premiums and fees paid or deferred for derivative contracts during the period | 7,126 | 0 | 0 |
Net (gains) losses on commodity and interest rate derivative contracts | 169,569 | 161,519 | 11,160 |
Cash settlements received on matured commodity derivative contracts | (211,723) | (10,187) | (30,905) |
Cash settlements paid on matured interest rate derivative contracts | 5,227 | 4,035 | 3,888 |
Fair value of derivative contracts terminated | (69,515) | ||
Derivative asset/(liability) at end of year, net | $ 316,691 | $ 220,734 | $ 66,711 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Goodwill impairment loss | $ 71,425 | $ 0 | $ 0 |
Asset retirement obligations incurred and assumed from business combinations | 90,927 | ||
Liabilities: | |||
Asset retirement obligations incurred during the current period | 2,699 | 52,829 | |
Asset Retirement Obligation, Revision of Estimate | $ 22,329 | 4,118 | |
Average inflation rate (in hundredths) | 2.00% | ||
Minimum [Member] | |||
Liabilities: | |||
Credit-adjusted risk-free interest rate (in hundredths) | 4.60% | ||
Maximum [Member] | |||
Liabilities: | |||
Credit-adjusted risk-free interest rate (in hundredths) | 5.51% | ||
Fair Value Measured on a Recurring Basis [Member] | |||
Assets: | |||
Commodity price derivative contracts | $ 327,447 | 225,697 | |
Interest rate derivative contracts | (10,400) | ||
Total derivative instruments | 317,047 | 225,697 | |
Liabilities: | |||
Commodity price derivative contracts | (99) | (294) | |
Interest rate derivative contracts | (257) | (4,669) | |
Total derivative instruments | (356) | (4,963) | |
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 1 [Member] | |||
Assets: | |||
Commodity price derivative contracts | 0 | 0 | |
Interest rate derivative contracts | 0 | ||
Total derivative instruments | 0 | 0 | |
Liabilities: | |||
Commodity price derivative contracts | 0 | 0 | |
Interest rate derivative contracts | 0 | 0 | |
Total derivative instruments | 0 | 0 | |
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 2 [Member] | |||
Assets: | |||
Commodity price derivative contracts | 333,380 | 232,167 | |
Interest rate derivative contracts | (10,400) | ||
Total derivative instruments | 322,980 | 232,167 | |
Liabilities: | |||
Commodity price derivative contracts | (99) | (294) | |
Interest rate derivative contracts | (257) | (4,669) | |
Total derivative instruments | (356) | (4,963) | |
Fair Value Measured on a Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Assets: | |||
Commodity price derivative contracts | (6,470) | ||
Interest rate derivative contracts | 0 | ||
Total derivative instruments | (6,470) | ||
Liabilities: | |||
Commodity price derivative contracts | (5,933) | 0 | |
Interest rate derivative contracts | 0 | ||
Total derivative instruments | (5,933) | $ 0 | |
Senior Notes due 2020 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt Instrument, Fair Value Disclosure | 165,400 | ||
Senior Notes due 2019 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt Instrument, Fair Value Disclosure | $ 14,400 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Measurements - Unobservable Inputs Reconciliation (Details) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Asset retirement obligations | $ 25,028 | $ 56,947 | $ 22,692 |
Liabilities added during the current period | 2,699 | 52,829 | |
Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||
Unobservable inputs at beginning of year | (6,470) | 566 | |
Total losses | 5,151 | (8,238) | |
Settlements | (4,614) | 1,202 | |
Unobservable inputs at end of year | (5,933) | (6,470) | $ 566 |
Change in fair value included in earnings related to derivatives still held as of end of year | $ (2,925) | $ (6,326) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in asset retirement obligations [Abstract] | |||
Asset retirement obligation at January 1, | $ 149,062 | $ 87,967 | |
Liabilities added during the current period | 2,699 | 52,829 | |
Asset retirement obligations assumed in a business combination | 88,228 | ||
Accretion expense | 10,238 | 5,889 | $ 2,800 |
Asset Retirement Obligation, Revision of Estimate | 22,329 | 4,118 | |
Asset Retirement Obligations Disposition Of Properties | (262) | (1,291) | |
Retirements | (838) | (450) | |
Total asset retirement obligation at December 31, | 271,456 | 149,062 | $ 87,967 |
Less: current obligations | (9,024) | (2,386) | |
Long-term asset retirement obligation at December 31, | $ 262,432 | $ 146,676 |
Commitments and Contingencies54
Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Gross future minimum transportation demand | |
2,016 | $ 14,957 |
2,017 | 12,512 |
2,018 | 11,696 |
2,019 | 9,661 |
2,020 | 410 |
Thereafter | 0 |
Total | $ 49,236 |
Minimum [Member] | |
Oil and Gas Delivery Commitments and Contracts | |
Remaining term of contracts | 1 year |
Maximum [Member] | |
Oil and Gas Delivery Commitments and Contracts | |
Remaining term of contracts | 5 years |
Commitments and Contingencies C
Commitments and Contingencies Commitments and contingencies - Development Commitment (Details) $ in Millions | Dec. 31, 2015USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Development Commitment, Remaining Minimum Amount Committed | $ 38 |
Members' Equity (Deficit) and56
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit - Preferred Units Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Preferred Stock, Liquidation Preference Per Share | $ 25 | |
Preferred units, outstanding | 13,881,873 | 13,881,873 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 335,444 | $ 335,444 |
Series A Preferred Units [Member] | ||
Preferred Stock, Liquidation Preference Per Share | $ 25 | |
Preferred Unit, Distribution Rate, Percentage | 7.875% | |
Preferred units, outstanding | 2,581,873 | 2,581,873 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 62,200 | $ 62,200 |
Series B Preferred Units [Member] | ||
Preferred Stock, Liquidation Preference Per Share | $ 25 | |
Preferred Unit, Distribution Rate, Percentage | 7.625% | |
Preferred units, outstanding | 7,000,000 | 7,000,000 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 169,265 | $ 169,265 |
Series C Preferred Units [Member] | ||
Preferred Stock, Liquidation Preference Per Share | $ 25 | |
Preferred Unit, Distribution Rate, Percentage | 7.75% | |
Preferred units, outstanding | 4,300,000 | 4,300,000 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 103,979 | $ 103,979 |
Members' Equity (Deficit) and57
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit - Common and Class B Units Rollforward (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 15, 2014 | |
Class of Stock [Line Items] | ||||
Stock Repurchase Program, Authorized Amount | $ 10,000,000 | |||
Treasury Stock, Carrying Basis | $ 4,900,000 | |||
Stock Repurchased During Period, Shares | 291,926 | |||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Treasury Stock, Shares, Acquired | (157,000) | (135,000) | ||
Common Units [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units | 83,452,000 | 78,337,000 | 58,706,000 | |
Partners' Capital Account, Units, Acquisitions | 0 | 1,075,000 | ||
Partners' Capital Account, Units, Sale of Units | 2,430,000 | 4,864,000 | 18,377,000 | |
Partners' Capital Account, Units, Unit-based Compensation | 1,418,000 | 386,000 | 179,000 | |
Partners' Capital Account, Units | 130,477,000 | 83,452,000 | 78,337,000 | |
EROC Merger [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units, Acquisitions | 27,886,000 | |||
LRE Merger [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units, Acquisitions | 15,448,000 |
Members' Equity and Net Income
Members' Equity and Net Income per Common and Class B Unit - Net Income (Loss) per Common and Class B Unit (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Antidilutive securities | |||
Net Income (Loss) Available to Common and class b unitholders, Basic | $ (1,909,933) | $ 46,148 | $ 56,877 |
Weighted Average Number of Shares Outstanding, Basic | 96,468,000 | 82,031,000 | 73,064,000 |
Weighted average units outstanding - diluted | 96,468,000 | 82,459,000 | 73,412,000 |
Earnings Per Share, Basic | $ (19.80) | $ 0.56 | $ 0.78 |
Earnings Per Share, Diluted | $ (19.80) | $ 0.55 | $ 0.77 |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 164,984 | ||
Phantom Share Units (PSUs) [Member] | |||
Antidilutive securities | |||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 0 | 428,000 | 348,000 |
Members' Equity (Deficit) and59
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit - Distributions Declared (Details) - $ / shares | Feb. 18, 2016 | Jan. 20, 2016 | Nov. 30, 2015 | Oct. 31, 2015 | Sep. 30, 2015 | Aug. 31, 2015 | Jul. 31, 2015 | Jun. 30, 2015 | May. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Nov. 30, 2013 | Oct. 31, 2013 | Sep. 30, 2013 | Aug. 31, 2013 | Jul. 31, 2013 | Jun. 30, 2013 | May. 31, 2013 | Apr. 30, 2013 | Mar. 31, 2013 | Feb. 28, 2013 | Jan. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2015 |
Preferred Stock, Liquidation Preference Per Share | $ 25 | ||||||||||||||||||||||||||||||||||||||
Series A Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.875% | ||||||||||||||||||||||||||||||||||||||
Preferred Stock, Liquidation Preference Per Share | $ 25 | ||||||||||||||||||||||||||||||||||||||
Series B Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.625% | ||||||||||||||||||||||||||||||||||||||
Preferred Stock, Liquidation Preference Per Share | $ 25 | ||||||||||||||||||||||||||||||||||||||
Series C Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.75% | ||||||||||||||||||||||||||||||||||||||
Preferred Stock, Liquidation Preference Per Share | $ 25 | ||||||||||||||||||||||||||||||||||||||
Common Units [Member] | |||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | $ 0.03 | $ 0.1175 | |||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis | 0.36 | 1.41 | |||||||||||||||||||||||||||||||||||||
Distributions Declared [Abstract] | |||||||||||||||||||||||||||||||||||||||
Cash Distributions Per Unit (in dollars per share) | $ 0.03 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.2075 | $ 0.2075 | $ 0.2075 | $ 0.2075 | $ 0.2075 | $ 0.2075 | $ 0.2075 | $ 0.2050 | $ 0.2050 | $ 0.2050 | $ 0.2025 | $ 0.2025 | $ 0.2025 | $ 0.2025 | |||
Cash Distributions Declared Date | Dec. 18, 2015 | Nov. 20, 2015 | Oct. 19, 2015 | Sep. 21, 2015 | Aug. 20, 2015 | Jul. 16, 2015 | Jun. 18, 2015 | May 19, 2015 | Apr. 15, 2015 | Mar. 18, 2015 | Feb. 17, 2015 | Jan. 22, 2015 | Dec. 16, 2014 | Nov. 20, 2014 | Oct. 20, 2014 | Sep. 19, 2014 | Aug. 19, 2014 | Jul. 16, 2014 | Jun. 24, 2014 | May 20, 2014 | Apr. 17, 2014 | Mar. 17, 2014 | Feb. 2, 2014 | Jan. 16, 2014 | Dec. 17, 2013 | Nov. 19, 2013 | Oct. 21, 2013 | Sep. 12, 2013 | Aug. 20, 2013 | Jul. 18, 2013 | Jun. 20, 2013 | Apr. 30, 2013 | Apr. 19, 2013 | Mar. 21, 2013 | Feb. 18, 2013 | Jan. 25, 2013 | |||
Cash Distributions Record Date | Jan. 4, 2016 | Dec. 1, 2015 | Nov. 2, 2015 | Oct. 1, 2015 | Sep. 1, 2015 | Aug. 3, 2015 | Jul. 1, 2015 | Jun. 1, 2015 | May 1, 2015 | Apr. 1, 2015 | Mar. 2, 2015 | Feb. 2, 2015 | Jan. 2, 2015 | Dec. 1, 2014 | Nov. 3, 2014 | Oct. 1, 2014 | Sep. 2, 2014 | Aug. 1, 2014 | Jul. 1, 2014 | Jun. 2, 2014 | May 1, 2014 | Apr. 1, 2014 | Mar. 3, 2014 | Feb. 3, 2014 | Jan. 2, 2014 | Dec. 2, 2013 | Nov. 1, 2013 | Oct. 1, 2013 | Sep. 3, 2013 | Aug. 1, 2013 | Jul. 1, 2013 | Jun. 3, 2013 | May 1, 2013 | Apr. 1, 2013 | Mar. 1, 2013 | Feb. 4, 2013 | |||
Cash Distributions Payment Date | Jan. 14, 2016 | Dec. 15, 2015 | Nov. 13, 2015 | Oct. 15, 2015 | Sep. 14, 2015 | Aug. 14, 2015 | Jul. 15, 2015 | Jun. 12, 2015 | May 15, 2015 | Apr. 14, 2015 | Mar. 17, 2015 | Feb. 13, 2015 | Jan. 14, 2015 | Dec. 15, 2014 | Nov. 14, 2014 | Oct. 15, 2014 | Sep. 12, 2014 | Aug. 14, 2014 | Jul. 15, 2014 | Jun. 13, 2014 | May 15, 2014 | Apr. 14, 2014 | Mar. 17, 2014 | Feb. 14, 2014 | Jan. 15, 2014 | Dec. 13, 2013 | Nov. 14, 2013 | Oct. 15, 2013 | Sep. 13, 2013 | Aug. 14, 2013 | Jul. 15, 2013 | Jun. 14, 2013 | May 15, 2013 | Apr. 12, 2013 | Mar. 15, 2013 | Feb. 14, 2013 | |||
Subsequent Event [Member] | Series A Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | $ 0.1641 | $ 0.1641 | |||||||||||||||||||||||||||||||||||||
Subsequent Event [Member] | Series B Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | 0.15885 | 0.15885 | |||||||||||||||||||||||||||||||||||||
Subsequent Event [Member] | Series C Preferred Units [Member] | |||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | 0.16146 | 0.16146 | |||||||||||||||||||||||||||||||||||||
Subsequent Event [Member] | Common Units [Member] | |||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | 0.03 | 0.03 | |||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis | $ 0.36 | $ 0.36 | |||||||||||||||||||||||||||||||||||||
Distributions Declared [Abstract] | |||||||||||||||||||||||||||||||||||||||
Cash Distributions Declared Date | Feb. 18, 2016 | Jan. 20, 2016 |
Unit-Based Compensation (Detail
Unit-Based Compensation (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Replacement share-based payment awards attributable to pre-combination services | $ 143,647 | |||
Replacement share-based payments, weighted average grant date fair value | $ 9.01 | |||
Accrued liability | $ 1,100,000 | |||
Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $ 11,000,000 | |||
Unrecognized compensation cost recognition period (in years) | 1 year 7 months | |||
Restricted Stock Units (RSUs) [Member] | Employee [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 1,613 | |||
Phantom Share Units (PSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $ 2,300,000 | |||
Unrecognized compensation cost recognition period (in years) | 1 year 2 months | |||
VNR LTIP [Member] | Board Member [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Common units granted to VNR employees and board member (in units) | 26,334 | |||
VNR LTIP [Member] | Employee [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Common units granted to VNR employees and board member (in units) | 175,297 | |||
VNR LTIP [Member] | Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 152,069 | |||
Granted (in dollars per unit) | $ 15.17 | $ 29.02 | $ 28.70 | |
VNR LTIP [Member] | Phantom Share Units (PSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 124,240 | |||
Granted (in dollars per unit) | $ 28.29 | |||
Amended Agreements [Member] | Executive Officer [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Common units granted to VNR employees and board member (in units) | 360,762 | |||
Amended Agreements [Member] | Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio of aggregate restricted units that will vest on each one-year anniversary | 33.33% | |||
Vesting period | 3 years | |||
Amended Agreements [Member] | Phantom Share Units (PSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Ratio of aggregate restricted units that will vest on each one-year anniversary | 33.33% | |||
Selling, General and Administrative Expenses [Member] | Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash unit-based compensation expense | $ 16,900,000 | $ 10,700,000 | $ 3,400,000 | |
Selling, General and Administrative Expenses [Member] | Phantom Share Units (PSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash unit-based compensation expense | 1,700,000 | $ 1,000,000 | $ 2,600,000 | |
Selling, General and Administrative Expenses [Member] | Amended Agreements [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash unit-based compensation expense | $ 1,100,000 | |||
Minimum [Member] | Employee [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Maximum [Member] | Employee [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 4 years |
Unit-Based Compensation - Summa
Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of Non-vested Units | |||
Replacement share-based payment awards attributable to pre-combination services | $ 143,647 | ||
Weighted Average Grant Date Fair Value | |||
Replacement share-based payments, weighted average grant date fair value | $ 9.01 | ||
Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation cost recognition period (in years) | 1 year 7 months | ||
Restricted Stock Units (RSUs) [Member] | VNR LTIP [Member] | |||
Number of Non-vested Units | |||
Non-vested units, beginning of year (in units) | 440,047 | ||
Granted (in units) | 562,393 | ||
Forfeited (in units) | (17,670) | ||
Vested (in units) | (152,069) | ||
Non-vested units, end of year (in units) | 976,348 | 440,047 | |
Weighted Average Grant Date Fair Value | |||
Non-vested units at beginning of year (in dollars per unit) | $ 28.87 | ||
Granted (in dollars per unit) | 15.17 | $ 29.02 | $ 28.70 |
Forfeited (in dollars per unit) | 20.54 | ||
Vested (in dollars per unit) | 26.04 | ||
Non-vested units at end of year (in dollars per unit) | $ 18.29 | $ 28.87 |
Unit-Based Compensation Unit-62
Unit-Based Compensation Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - Phantom Share Units (PSUs) [Member] - VNR Long Term Incentive Plan [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2013 | |
Granted (in dollars per unit) | $ 28.29 | |
Number of Non-vested Units | ||
Non-vested units, beginning of year (in units) | 330,321 | |
Forfeited (in units) | (2,979) | |
Vested (in units) | (124,240) | |
Non-vested units, end of year (in units) | 203,102 | |
Weighted Average Grant Date Fair Value | ||
Non-vested units at beginning of year (in dollars per unit) | $ 28.58 | |
Forfeited (in dollars per unit) | 28.28 | |
Vested (in dollars per unit) | 21.57 | |
Non-vested units at end of year (in dollars per unit) | $ 20.99 |
Shelf Registration Statements (
Shelf Registration Statements (Details) | 12 Months Ended |
Dec. 31, 2015USD ($)shares | |
Shelf Registration Statements [Line Items] | |
Registration Payment Arrangement, Maximum Potential Consideration | $ 500,000,000 |
Common Units [Member] | |
Shelf Registration Statements [Line Items] | |
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | 600,000 |
Distribution Agreement 2013 [Member] | Common Units [Member] | |
Shelf Registration Statements [Line Items] | |
Maximum offering under equity distribution agreement | 400,000,000 |
Proceeds from Issuance or Sale of Equity | $ 35,500,000 |
Units issued under public offerings (in units) | shares | 2,430,170 |
Distribution Agreement 2013 [Member] | Series A Preferred Units [Member] | |
Shelf Registration Statements [Line Items] | |
Maximum offering under equity distribution agreement | $ 50,000,000 |
Distribution Agreement 2013 [Member] | Series B Preferred Units [Member] | |
Shelf Registration Statements [Line Items] | |
Maximum offering under equity distribution agreement | 100,000,000 |
Distribution Agreement 2013 [Member] | Series C Preferred Units [Member] | |
Shelf Registration Statements [Line Items] | |
Maximum offering under equity distribution agreement | $ 75,000,000 |
Condensed Consolidating Finan64
Condensed Consolidating Financial Statements Unaudited Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Condensed Financial Statements, Captions [Line Items] | ||
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions | 100.00% | |
ASSETS: | ||
Accounts receivable – affiliates | $ 0 | |
Other current assets | 358,522 | $ 286,233 |
Oil and natural gas properties | 1,721,976 | |
Total other long-term assets | 628,799 | |
Total assets | 2,709,297 | 3,793,592 |
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): | ||
Accounts payable – affiliates | 1,757 | |
Investment in subsidiaries | 0 | |
Other current liabilities | 200,251 | |
Other long-term liabilities | 303,088 | |
Long-term debt | 2,291,636 | 1,932,816 |
Members’ equity (deficit) | (87,435) | 1,534,116 |
Total liabilities and members’ equity (deficit) | 2,709,297 | $ 3,793,592 |
Reportable Legal Entities | Parent | ||
ASSETS: | ||
Accounts receivable – affiliates | 1,897,495 | |
Other current assets | 0 | |
Oil and natural gas properties | 0 | |
Total other long-term assets | 7,449 | |
Total assets | 1,904,944 | |
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): | ||
Accounts payable – affiliates | 0 | |
Investment in subsidiaries | 2,211,408 | |
Other current liabilities | 16,394 | |
Other long-term liabilities | 0 | |
Long-term debt | 548,439 | |
Members’ equity (deficit) | (871,297) | |
Total liabilities and members’ equity (deficit) | 1,904,944 | |
Reportable Legal Entities | Issuer | ||
ASSETS: | ||
Accounts receivable – affiliates | 102,678 | |
Other current assets | 94,946 | |
Oil and natural gas properties | 1,612,791 | |
Total other long-term assets | 530,914 | |
Total assets | 2,341,329 | |
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): | ||
Accounts payable – affiliates | 2,499,858 | |
Investment in subsidiaries | 10,826 | |
Other current liabilities | 165,442 | |
Other long-term liabilities | 230,149 | |
Long-term debt | 55,197 | |
Members’ equity (deficit) | (620,143) | |
Total liabilities and members’ equity (deficit) | 2,341,329 | |
Reportable Legal Entities | Guarantors | ||
ASSETS: | ||
Accounts receivable – affiliates | 499,685 | |
Other current assets | 263,576 | |
Oil and natural gas properties | 109,185 | |
Total other long-term assets | 90,436 | |
Total assets | 962,882 | |
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): | ||
Accounts payable – affiliates | 1,757 | |
Investment in subsidiaries | 0 | |
Other current liabilities | 18,415 | |
Other long-term liabilities | 72,939 | |
Long-term debt | 1,688,000 | |
Members’ equity (deficit) | (818,229) | |
Total liabilities and members’ equity (deficit) | 962,882 | |
Consolidating Entries | ||
ASSETS: | ||
Accounts receivable – affiliates | (2,499,858) | |
Other current assets | 0 | |
Oil and natural gas properties | 0 | |
Total other long-term assets | 0 | |
Total assets | (2,499,858) | |
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT): | ||
Accounts payable – affiliates | (2,499,858) | |
Investment in subsidiaries | (2,222,234) | |
Other current liabilities | 0 | |
Other long-term liabilities | 0 | |
Long-term debt | 0 | |
Members’ equity (deficit) | 2,222,234 | |
Total liabilities and members’ equity (deficit) | $ (2,499,858) |
Condensed Consolidating Finan65
Condensed Consolidating Financial Statements Unaudited Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed Financial Statements, Captions [Line Items] | |||||||
Total revenues | $ 566,643 | $ 788,065 | $ 454,504 | ||||
Operating expenses | 187,230 | ||||||
Depreciation, depletion, amortization and accretion | 247,119 | 226,937 | 167,535 | ||||
Selling, general and administrative expenses | 55,076 | 30,839 | 25,942 | ||||
Impairment of oil and natural gas properties | $ 484,855 | $ 491,487 | $ 733,365 | $ 132,610 | 1,842,317 | 234,434 | 0 |
Goodwill impairment loss | 71,425 | 0 | 0 | ||||
Income (loss) from operations | (1,836,524) | 101,466 | 115,095 | ||||
Interest expense | (87,573) | (69,765) | (61,148) | ||||
Other non-operating income | 40,923 | ||||||
Income (loss) before equity in earnings of subsidiaries | (1,883,174) | ||||||
Equity in earnings (loss) of subsidiaries | 0 | ||||||
Net Income (loss) | (1,883,174) | 64,345 | 59,511 | ||||
Less: Distributions to Preferred unitholders | (26,759) | (18,197) | (2,634) | ||||
Net Income (Loss) Available to Common and class b unitholders, Basic | (1,909,933) | $ 46,148 | $ 56,877 | ||||
Reportable Legal Entities | Parent | |||||||
Condensed Financial Statements, Captions [Line Items] | |||||||
Total revenues | 0 | ||||||
Operating expenses | 0 | ||||||
Depreciation, depletion, amortization and accretion | 0 | ||||||
Selling, general and administrative expenses | 8,239 | ||||||
Impairment of oil and natural gas properties | 0 | ||||||
Goodwill impairment loss | 0 | ||||||
Income (loss) from operations | (8,239) | ||||||
Interest expense | (46,018) | ||||||
Other non-operating income | 0 | ||||||
Income (loss) before equity in earnings of subsidiaries | (54,257) | ||||||
Equity in earnings (loss) of subsidiaries | (1,828,917) | ||||||
Net Income (loss) | (1,883,174) | ||||||
Less: Distributions to Preferred unitholders | (26,759) | ||||||
Net Income (Loss) Available to Common and class b unitholders, Basic | (1,909,933) | ||||||
Reportable Legal Entities | Issuer | |||||||
Condensed Financial Statements, Captions [Line Items] | |||||||
Total revenues | 388,206 | ||||||
Operating expenses | 183,044 | ||||||
Depreciation, depletion, amortization and accretion | 240,891 | ||||||
Selling, general and administrative expenses | 17,008 | ||||||
Impairment of oil and natural gas properties | 1,806,319 | ||||||
Goodwill impairment loss | 71,425 | ||||||
Income (loss) from operations | (1,930,481) | ||||||
Interest expense | (375) | ||||||
Other non-operating income | 41,644 | ||||||
Income (loss) before equity in earnings of subsidiaries | (1,889,212) | ||||||
Equity in earnings (loss) of subsidiaries | (37,911) | ||||||
Net Income (loss) | (1,927,123) | ||||||
Less: Distributions to Preferred unitholders | 0 | ||||||
Net Income (Loss) Available to Common and class b unitholders, Basic | (1,927,123) | ||||||
Reportable Legal Entities | Guarantors | |||||||
Condensed Financial Statements, Captions [Line Items] | |||||||
Total revenues | 178,437 | ||||||
Operating expenses | 4,186 | ||||||
Depreciation, depletion, amortization and accretion | 6,228 | ||||||
Selling, general and administrative expenses | 29,829 | ||||||
Impairment of oil and natural gas properties | 35,998 | ||||||
Goodwill impairment loss | 0 | ||||||
Income (loss) from operations | 102,196 | ||||||
Interest expense | (41,180) | ||||||
Other non-operating income | (721) | ||||||
Income (loss) before equity in earnings of subsidiaries | 60,295 | ||||||
Equity in earnings (loss) of subsidiaries | 0 | ||||||
Net Income (loss) | 60,295 | ||||||
Less: Distributions to Preferred unitholders | 0 | ||||||
Net Income (Loss) Available to Common and class b unitholders, Basic | 60,295 | ||||||
Consolidating Entries | |||||||
Condensed Financial Statements, Captions [Line Items] | |||||||
Total revenues | 0 | ||||||
Operating expenses | 0 | ||||||
Depreciation, depletion, amortization and accretion | 0 | ||||||
Selling, general and administrative expenses | 0 | ||||||
Impairment of oil and natural gas properties | 0 | ||||||
Goodwill impairment loss | 0 | ||||||
Income (loss) from operations | 0 | ||||||
Interest expense | 0 | ||||||
Other non-operating income | 0 | ||||||
Income (loss) before equity in earnings of subsidiaries | 0 | ||||||
Equity in earnings (loss) of subsidiaries | 1,866,828 | ||||||
Net Income (loss) | 1,866,828 | ||||||
Less: Distributions to Preferred unitholders | 0 | ||||||
Net Income (Loss) Available to Common and class b unitholders, Basic | $ 1,866,828 |
Condensed Consolidating Finan66
Condensed Consolidating Financial Statements Unaudited Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating activities | |||
Payments to Acquire Property, Plant, and Equipment | $ 644 | $ 1,356 | $ 1,975 |
Additions to natural gas and oil properties | (112,639) | (142,015) | (56,661) |
Payments to Acquire Oil and Gas Property | (12,970) | (1,302,568) | (272,057) |
Cash acquired from LRE and Eagle Rock acquisition | 18,503 | 0 | 0 |
Proceeds from the sale of oil and natural gas properties | 1,777 | 4,973 | 0 |
Deposits and prepayments of natural gas and oil properties | (22,171) | (5,236) | (67,284) |
Financing activities | |||
Repurchase of units under the common unit buyback program | (2,399) | (2,498) | 0 |
Distributions to Preferred unitholders | (26,760) | (17,290) | (2,426) |
Payments of Financing Costs | (12,067) | (1,168) | $ (2,133) |
Reportable Legal Entities | |||
Operating activities | |||
Net cash flows (used in) provided by operating activities | 370,084 | ||
Payments to Acquire Property, Plant, and Equipment | 644 | ||
Additions to natural gas and oil properties | (112,639) | ||
Payments to Acquire Oil and Gas Property | (12,970) | ||
Cash acquired from LRE and Eagle Rock acquisition | 18,503 | ||
Proceeds from the sale of oil and natural gas properties | 1,777 | ||
Deposits and prepayments of natural gas and oil properties | (22,171) | ||
Investing activities | |||
Net cash flows provided by (used in) investing activities | (128,144) | ||
Financing activities | |||
Proceeds from long-term debt | 420,000 | ||
Repayment of debt | (508,617) | ||
Proceeds from common unit offerings, net | 35,544 | ||
Repurchase of units under the common unit buyback program | (2,399) | ||
Repurchase of units under the common unit buyback program | (147,641) | ||
Distributions to Preferred unitholders | (26,760) | ||
Payments of Financing Costs | (12,067) | ||
Net cash flows used in financing activities | (241,940) | ||
Net increase in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | 0 | |
Cash and cash equivalents at end of period | 0 | 0 | |
Reportable Legal Entities | Parent | |||
Operating activities | |||
Net cash flows (used in) provided by operating activities | 153,323 | ||
Payments to Acquire Property, Plant, and Equipment | 0 | ||
Additions to natural gas and oil properties | 0 | ||
Payments to Acquire Oil and Gas Property | 0 | ||
Cash acquired from LRE and Eagle Rock acquisition | 0 | ||
Proceeds from the sale of oil and natural gas properties | 0 | ||
Deposits and prepayments of natural gas and oil properties | 0 | ||
Investing activities | |||
Net cash flows provided by (used in) investing activities | $ 0 | ||
Financing activities | |||
Proceeds from long-term debt | |||
Repayment of debt | |||
Proceeds from common unit offerings, net | $ 35,544 | ||
Repurchase of units under the common unit buyback program | (2,399) | ||
Repurchase of units under the common unit buyback program | (147,641) | ||
Distributions to Preferred unitholders | (26,760) | ||
Payments of Financing Costs | (12,067) | ||
Net cash flows used in financing activities | (153,323) | ||
Net increase in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | ||
Cash and cash equivalents at end of period | 0 | ||
Reportable Legal Entities | Issuer | |||
Operating activities | |||
Net cash flows (used in) provided by operating activities | 149,601 | ||
Payments to Acquire Property, Plant, and Equipment | 219 | ||
Additions to natural gas and oil properties | (111,738) | ||
Payments to Acquire Oil and Gas Property | (12,933) | ||
Cash acquired from LRE and Eagle Rock acquisition | 0 | ||
Proceeds from the sale of oil and natural gas properties | 1,777 | ||
Deposits and prepayments of natural gas and oil properties | (22,171) | ||
Investing activities | |||
Net cash flows provided by (used in) investing activities | (145,284) | ||
Financing activities | |||
Proceeds from long-term debt | 0 | ||
Repayment of debt | (4,317) | ||
Proceeds from common unit offerings, net | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Distributions to Preferred unitholders | 0 | ||
Payments of Financing Costs | 0 | ||
Net cash flows used in financing activities | (4,317) | ||
Net increase in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | ||
Cash and cash equivalents at end of period | 0 | ||
Reportable Legal Entities | Guarantors | |||
Operating activities | |||
Net cash flows (used in) provided by operating activities | 67,160 | ||
Payments to Acquire Property, Plant, and Equipment | 425 | ||
Additions to natural gas and oil properties | (901) | ||
Payments to Acquire Oil and Gas Property | (37) | ||
Cash acquired from LRE and Eagle Rock acquisition | 18,503 | ||
Proceeds from the sale of oil and natural gas properties | 0 | ||
Deposits and prepayments of natural gas and oil properties | 0 | ||
Investing activities | |||
Net cash flows provided by (used in) investing activities | 17,140 | ||
Financing activities | |||
Proceeds from long-term debt | 420,000 | ||
Repayment of debt | (504,300) | ||
Proceeds from common unit offerings, net | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Distributions to Preferred unitholders | 0 | ||
Payments of Financing Costs | 0 | ||
Net cash flows used in financing activities | (84,300) | ||
Net increase in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | ||
Cash and cash equivalents at end of period | 0 | ||
Consolidating Entries | |||
Operating activities | |||
Net cash flows (used in) provided by operating activities | 0 | ||
Payments to Acquire Property, Plant, and Equipment | 0 | ||
Additions to natural gas and oil properties | 0 | ||
Payments to Acquire Oil and Gas Property | 0 | ||
Cash acquired from LRE and Eagle Rock acquisition | 0 | ||
Proceeds from the sale of oil and natural gas properties | 0 | ||
Deposits and prepayments of natural gas and oil properties | 0 | ||
Investing activities | |||
Net cash flows provided by (used in) investing activities | 0 | ||
Financing activities | |||
Proceeds from long-term debt | 0 | ||
Repayment of debt | 0 | ||
Proceeds from common unit offerings, net | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Repurchase of units under the common unit buyback program | 0 | ||
Distributions to Preferred unitholders | 0 | ||
Payments of Financing Costs | 0 | ||
Net cash flows used in financing activities | 0 | ||
Net increase in cash and cash equivalents | 0 | ||
Cash and cash equivalents at beginning of period | 0 | 0 | |
Cash and cash equivalents at end of period | $ 0 | $ 0 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands | Feb. 18, 2016 | Feb. 10, 2016 | Jan. 20, 2016 | Nov. 30, 2015 | Oct. 31, 2015 | Sep. 30, 2015 | Aug. 31, 2015 | Jul. 31, 2015 | Jun. 30, 2015 | May. 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | May. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Nov. 30, 2013 | Oct. 31, 2013 | Sep. 30, 2013 | Aug. 31, 2013 | Jul. 31, 2013 | Jun. 30, 2013 | May. 31, 2013 | Apr. 30, 2013 | Mar. 31, 2013 | Feb. 28, 2013 | Jan. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2015 |
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Debt amount outstanding | $ 1,938,986 | $ 2,313,788 | ||||||||||||||||||||||||||||||||||||||
Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Required repurchase of aggregate amount of debt | $ 50,000 | |||||||||||||||||||||||||||||||||||||||
Common Units [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Cash Distributions Declared Date | Dec. 18, 2015 | Nov. 20, 2015 | Oct. 19, 2015 | Sep. 21, 2015 | Aug. 20, 2015 | Jul. 16, 2015 | Jun. 18, 2015 | May 19, 2015 | Apr. 15, 2015 | Mar. 18, 2015 | Feb. 17, 2015 | Jan. 22, 2015 | Dec. 16, 2014 | Nov. 20, 2014 | Oct. 20, 2014 | Sep. 19, 2014 | Aug. 19, 2014 | Jul. 16, 2014 | Jun. 24, 2014 | May 20, 2014 | Apr. 17, 2014 | Mar. 17, 2014 | Feb. 2, 2014 | Jan. 16, 2014 | Dec. 17, 2013 | Nov. 19, 2013 | Oct. 21, 2013 | Sep. 12, 2013 | Aug. 20, 2013 | Jul. 18, 2013 | Jun. 20, 2013 | Apr. 30, 2013 | Apr. 19, 2013 | Mar. 21, 2013 | Feb. 18, 2013 | Jan. 25, 2013 | ||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | $ 0.03 | $ 0.1175 | ||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis | $ 0.36 | $ 1.41 | ||||||||||||||||||||||||||||||||||||||
Common Units [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Cash Distributions Declared Date | Feb. 18, 2016 | Jan. 20, 2016 | ||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | $ 0.03 | $ 0.03 | ||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis | 0.36 | 0.36 | ||||||||||||||||||||||||||||||||||||||
Series A Preferred Units [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | 0.1641 | 0.1641 | ||||||||||||||||||||||||||||||||||||||
Series B Preferred Units [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | 0.15885 | 0.15885 | ||||||||||||||||||||||||||||||||||||||
Series C Preferred Units [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit | $ 0.16146 | $ 0.16146 | ||||||||||||||||||||||||||||||||||||||
Cumulative Preferred units | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Cash Distributions Declared Date | Feb. 18, 2016 | Jan. 20, 2016 | ||||||||||||||||||||||||||||||||||||||
Subordinated Debt [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Extinguishment of Debt, Amount | 168,200 | |||||||||||||||||||||||||||||||||||||||
Debt amount outstanding | $ 75,600 | |||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | |||||||||||||||||||||||||||||||||||||||
Scenario, Forecast [Member] | ||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Extinguishment of Debt, Amount | $ 168,200 |