Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Mar. 10, 2017 | Jun. 30, 2016 | |
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 | Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 130,947,802 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 181,364,578 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues: | |||
Oil sales | $ 169,955 | $ 164,111 | $ 268,685 |
Natural gas sales | 174,263 | 193,496 | 285,439 |
Natural gas liquids sales | 44,462 | 39,620 | 70,489 |
Net gains (losses) on commodity derivative contracts | (44,072) | 169,416 | 163,452 |
Total revenues | 344,608 | 566,643 | 788,065 |
Production: | |||
Lease operating expenses | 159,672 | 146,654 | 132,515 |
Production and other taxes | 38,637 | 40,576 | 61,874 |
Depreciation, depletion, amortization and accretion | 149,790 | 247,119 | 226,937 |
Impairment of oil and natural gas properties | 494,270 | 1,842,317 | 234,434 |
Impairment of goodwill | 252,676 | 71,425 | 0 |
Restructuring Charges | 3,156 | 0 | 0 |
Selling, general and administrative expenses - Other | 48,362 | 55,076 | 30,839 |
Total costs and expenses | 1,146,563 | 2,403,167 | 686,599 |
Income (loss) from operations | (801,955) | (1,836,524) | 101,466 |
Other income (expense): | |||
Interest expense | (95,367) | (87,573) | (69,765) |
Net gains (losses) on interest rate derivative contracts | (2,867) | 153 | (1,933) |
Net gain (loss) on acquisitions of oil and natural gas properties | (4,979) | 40,533 | 34,523 |
Gain on extinguishment on debt | 89,714 | 0 | 0 |
Other | 447 | 237 | 54 |
Total other expense, net | (13,052) | (46,650) | (37,121) |
Net income (loss) | (815,007) | (1,883,174) | 64,345 |
Less: Net income attributable to non-controlling interests | (82) | 0 | 0 |
Net income (loss) attributable to Vanguard unitholders | (815,089) | (1,883,174) | 64,345 |
Less: Distributions to Preferred unitholders | (26,758) | (26,759) | (18,197) |
Net income (loss) attributable to Common and Class B unitholders | $ (841,847) | $ (1,909,933) | $ 46,148 |
Net income (loss) per Common and Class B unit: | |||
Earnings Per Share, Basic (in dollars per share) | $ (6.41) | $ (19.80) | $ 0.56 |
Earnings Per Share, Diluted (in dollars per share) | $ (6.41) | $ (19.80) | $ 0.55 |
Weighted average units outstanding: | |||
Weighted average units outstanding - basic (in shares) | 131,323 | 96,468 | 82,031 |
Weighted average units outstanding - diluted (in shares) | 131,323 | 96,468 | 82,459 |
Common Units [Member] | |||
Weighted average units outstanding: | |||
Weighted average units outstanding - basic (in shares) | 130,903 | 96,048 | 81,611 |
Weighted average units outstanding - diluted (in shares) | 130,903 | 96,048 | 82,039 |
Class B Units [Member] | |||
Weighted average units outstanding: | |||
Weighted average units outstanding - basic and diluted (in shares) | 420 | 420 | 420 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | $ 49,957 | $ 0 |
Trade accounts receivable, net | 97,138 | 115,200 |
Derivative assets | 0 | 236,886 |
Other currents assets | 7,944 | 6,436 |
Total current assets | 155,039 | 358,522 |
Oil and natural gas properties, at cost | 4,725,692 | 4,961,218 |
Accumulated depletion, amortization and impairment | (3,867,439) | (3,239,242) |
Oil and natural gas properties evaluated, net – full cost method | 858,253 | 1,721,976 |
Other assets | ||
Goodwill | 253,370 | 506,046 |
Derivative assets | 0 | 80,161 |
Other assets | 42,626 | 28,887 |
Total assets | 1,309,288 | 2,695,592 |
Accounts payable: | ||
Trade | 12,929 | 22,895 |
Affiliates | 1,443 | 1,757 |
Accrued liabilities: | ||
Lease operating | 14,909 | 19,910 |
Developmental capital | 6,676 | 26,726 |
Interest | 13,345 | 11,958 |
Production and other taxes | 32,663 | 40,472 |
Other | 5,416 | 10,378 |
Derivative liabilities | 125 | 356 |
Oil and natural gas revenue payable | 33,672 | 44,823 |
Distributions payable | 0 | 5,018 |
Long-term debt classified as current | 1,753,345 | 0 |
Other current liabilities | 14,160 | 17,715 |
Total current liabilities | 1,888,683 | 202,008 |
Long-term debt | 15,475 | 2,277,931 |
Asset retirement obligations | 264,552 | 262,432 |
Other long-term liabilities | 39,443 | 40,656 |
Total liabilities | 2,208,153 | 2,783,027 |
Commitments and contingencies (Note 8) | ||
Members’ deficit | ||
Total VNR members’ deficit | (905,708) | (87,435) |
Non-controlling interest in subsidiary | 6,843 | 0 |
Total members’ deficit | (898,865) | (87,435) |
Total liabilities and members’ deficit | 1,309,288 | 2,695,592 |
Cumulative Preferred Stock [Member] | ||
Members’ deficit | ||
Total VNR members’ deficit | 335,444 | 335,444 |
Common Units [Member] | ||
Members’ deficit | ||
Total VNR members’ deficit | (1,248,767) | (430,494) |
Class B Units [Member] | ||
Members’ deficit | ||
Total VNR members’ deficit | $ 7,615 | $ 7,615 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2016 | Dec. 31, 2015 |
Members’ deficit | ||
Preferred units, outstanding | 13,881,873 | 13,881,873 |
Cumulative Preferred units | ||
Members’ deficit | ||
Preferred Unit, Issued | 13,881,873 | 13,881,873 |
Preferred units, outstanding | 13,881,873 | 13,881,873 |
Common Units [Member] | ||
Members’ deficit | ||
Common Unit, Issued | 131,008,670 | 130,476,978 |
Common Unit, Outstanding | 131,008,670 | 130,476,978 |
Class B Units [Member] | ||
Members’ 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 | Noncontrolling Interest [Member] | Common Units [Member] | 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, 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 | |||||||
Repurchase of units under the common unit buyback program | (2,498) | (2,498) | |||||||||
Distributions to Preferred unitholders (see Note 9) | (18,197) | (18,197) | |||||||||
Distributions to Common and Class B unitholders (see Note 9) | (207,883) | (207,883) | |||||||||
Issuance costs related to prior period equity transactions | 88 | 371 | |||||||||
Unit-based compensation | 7,777 | 7,777 | |||||||||
Net income (loss) | 64,345 | 64,345 | |||||||||
Net income (loss) | 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 | $ 253,068 | $ 253,068 | $ 119,315 | $ 119,315 | |||||
Repurchase of units under the common unit buyback program | (2,399) | (2,399) | |||||||||
Distributions to Preferred unitholders (see Note 9) | (26,760) | (26,760) | |||||||||
Distributions to Common and Class B unitholders (see Note 9) | (134,019) | (134,019) | |||||||||
Issuance costs related to prior period equity transactions | 593 | $ 3,961 | $ 5,560 | ||||||||
Unit-based compensation | 16,874 | 16,874 | |||||||||
Net income (loss) | (1,883,174) | ||||||||||
Net income (loss) | (1,883,174) | (1,883,174) | |||||||||
Balance at Dec. 31, 2015 | (87,435) | (430,494) | 335,444 | 7,615 | |||||||
Increase (Decrease) in Members' Equity (Deficit) | |||||||||||
Distributions to Preferred unitholders (see Note 9) | $ (5,575) | (5,575) | |||||||||
Distributions to Common and Class B unitholders (see Note 9) | (7,998) | (7,998) | |||||||||
Issuance costs related to prior period equity transactions | $ 250 | 250 | |||||||||
Unit-based compensation | 10,639 | 10,639 | |||||||||
Non-controlling interest in subsidiary | 7,452 | $ 7,452 | |||||||||
Net income (loss) | (815,089) | ||||||||||
Net income (loss) | (815,007) | 82 | (815,089) | ||||||||
Potato Hills cash distribution to non-controlling interest | (691) | (691) | |||||||||
Balance at Dec. 31, 2016 | $ (898,865) | $ 6,843 | $ (1,248,767) | $ 335,444 | $ 7,615 |
CONSOLIDATED STATEMENTS OF MEM6
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cumulative Preferred units | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 371 | ||
Common Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 250 | ||
Common Units [Member] | Member Units [Member] | |||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ 250 | $ 593 | $ 88 |
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 ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities | |||
Net income (loss) | $ (815,007) | $ (1,883,174) | $ 64,345 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 149,790 | 247,119 | 226,937 |
Impairment of oil and natural gas properties | 494,270 | 1,842,317 | 234,434 |
Impairment of goodwill | 252,676 | 71,425 | 0 |
Amortization of deferred financing costs | 4,565 | 4,206 | 3,516 |
Amortization of debt discount | 3,746 | 1,071 | 269 |
Compensation related items | 10,639 | 16,874 | 10,706 |
Post Eagle Rock Merger severance costs | 0 | 13,955 | 0 |
Net (gains) losses on commodity and interest rate derivative contracts | 46,939 | (169,569) | (161,519) |
Net cash settlements received on matured commodity derivative contracts | 226,876 | 211,723 | 10,187 |
Net cash settlements paid on matured interest rate derivative contracts | (13,398) | (5,227) | (4,035) |
Cash received on termination of derivative contracts | 53,955 | 40,998 | 0 |
Net (gain) loss on acquisitions of oil and natural gas properties | 4,979 | (40,533) | (34,523) |
Gain on extinguishment of debt | (89,714) | 0 | 0 |
Changes in operating assets and liabilities: | |||
Trade accounts receivable | 9,559 | 53,423 | (69,908) |
Payables to affiliates | (314) | 934 | 574 |
Premiums paid on commodity derivative contracts | (430) | (4,235) | 0 |
Other current assets | (3,050) | (1,615) | (1,669) |
Accounts payable and oil and natural gas revenue payable | (17,954) | (555) | 22,166 |
Accrued expenses and other current liabilities | (41,582) | (43,320) | 29,377 |
Other assets | 13,735 | 14,267 | 8,895 |
Net cash provided by operating activities | 290,280 | 370,084 | 339,752 |
Investing activities | |||
Additions to property and equipment | (101) | (644) | (1,356) |
Potato Hills Gas Gathering System acquisition | (7,501) | 0 | 0 |
Additions to oil and natural gas properties | (64,537) | (112,639) | (142,015) |
Acquisitions of oil and natural gas properties and derivative contracts | 0 | (12,970) | (1,302,568) |
Cash acquired in the LRE and Eagle Rock Mergers | 0 | 18,503 | 0 |
Proceeds from the sale of oil and natural gas properties | 298,701 | 1,777 | 4,973 |
Deposits and prepayments of oil and natural gas properties | (19,740) | (22,171) | (5,236) |
Net cash provided by (used in) investing activities | 206,822 | (128,144) | (1,446,202) |
Financing activities | |||
Proceeds from long-term debt | 93,500 | 420,000 | 1,388,000 |
Repayment of debt | (517,157) | (508,617) | (488,000) |
Proceeds from preferred unit offerings, net | 0 | 0 | 274,423 |
Proceeds from common unit offerings, net | 0 | 35,544 | 147,814 |
Repurchase of units under the common unit buyback program | 0 | (2,399) | (2,498) |
Distributions to Preferred unitholders | (6,690) | (26,760) | (17,290) |
Distributions to Common and Class B members | (11,902) | (147,641) | (206,649) |
Potato Hills distribution to non-controlling interest | (691) | 0 | 0 |
Financing fees | (4,205) | (12,067) | (1,168) |
Net cash provided by (used in) financing activities | (447,145) | (241,940) | 1,094,632 |
Net increase (decrease) in cash and cash equivalents | 49,957 | 0 | (11,818) |
Cash and cash equivalents, beginning of year | 0 | 0 | 11,818 |
Cash and cash equivalents, end of year | 49,957 | 0 | 0 |
Supplemental cash flow information: | |||
Cash paid for interest | 85,371 | 83,557 | 66,434 |
Non-cash financing and investing activities: | |||
Asset retirement obligations | 8,935 | 24,766 | 56,947 |
Assets acquired under financing obligations | 0 | 0 | 31,502 |
Noncash or Part Noncash Acquisition, Accounts Receivable And Other Current Assets Acquired | 0 | 44,201 | 0 |
Net derivative assets acquired in a business combination | 0 | 166,758 | 0 |
Noncash or part non cash acquisition, Oil and gas properties | 0 | 672,178 | 0 |
Noncash or Part Noncash Acquisition, Other Assets Acquired | 0 | 10,001 | 0 |
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed | 0 | 70,085 | |
Asset retirement obligations assumed in a business combination | 0 | 88,228 | 0 |
Noncash or Part Noncash Acquisition, Debt Assumed | 0 | 446,550 | 0 |
Noncash or Part Noncash Acquisition, Payables Assumed | 0 | 40,571 | 0 |
Noncash or Part Noncash Acquisition, Noncash Financial or Equity Instrument Consideration, Value Issued | $ 0 | $ 381,904 | $ 0 |
Description of the Business
Description of the Business | 12 Months Ended |
Dec. 31, 2016 | |
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 resume making 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, 2016 , 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 Piceance Basin in Colorado; • the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama; • the Arkoma Basin in Arkansas and Oklahoma; • the Big Horn Basin in Wyoming and Montana; • the Williston Basin in North Dakota and Montana; • the Anadarko Basin in Oklahoma and North Texas; • 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 (“ECFP”), 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 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 Acquisition Partnership II, L.P. (“ERAP II”). |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
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. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements. (b) Chapter 11 Proceedings On February 1, 2017 (the “Chapter 11 Filing Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. See Note 2 for a discussion of the Chapter 11 Proceedings (as defined in Note 2). (c) New Pronouncements Issued But Not Yet Adopted: In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five-step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation and begun contract review and documentation. The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catch-up transition method). The Company is currently evaluating the available adoption methods. 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. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16, pursuant to Staff Announcements at the March 3, EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU provide clarifying guidance in certain narrow areas and adds some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on the calculation or presentation of our results of operations, cash flows, or financial position. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) to simplify the accounting for goodwill impairment. The guidance eliminates the need for Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The new standard also eliminates the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. The revised guidance will be applied prospectively, and is effective for public companies for fiscal years beginning January 1, 2020. Early adoption is permitted for any impairment tests performed after January 1, 2017. The Company plans to early adopt this guidance and will apply it prospectively for all goodwill impairment tests performed on or after January 1, 2017. As a result of adopting this guidance, we do not expect to record a goodwill impairment in the near term due to the negative carrying value of the reporting unit at December 31, 2016. (d) Cash Equivalents: The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. (e) 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. (f) 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. (g) 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, 2016 of $494.3 million . Such impairment was recognized during the first, second and fourth quarters of 2016 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2016 $ 207,764 $2.41 $46.16 Second quarter 2016 $ 157,894 $2.24 $42.91 Third quarter 2016 $ — $2.29 $41.48 Fourth quarter 2016 $ 128,612 $2.47 $42.60 Total $ 494,270 The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2016 were the reduction in our proved reserves quantities due to the reclassification of our proved undeveloped reserves to contingent resources due to uncertainties surrounding the availability of financing that would be necessary to develop these reserves and the impact of sustained lower commodity prices. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices. Such impairment was recorded during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ 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 affecting the 2015 impairment 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. 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. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas property costs 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. (h) 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 2016 , 2015 and 2014 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 also performed interim impairment tests at each quarter end, commencing with the quarter ended December 31, 2014. At each measurement date, if the Company was required to perform 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 included: (i) observable forward prices for commodities at the respective measurement date and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. At the respective measurement dates of March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016 , the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test at these interim dates. Based on the results of the the second step of the interim goodwill impairment test, we recorded a non-cash goodwill impairment loss of $252.7 million during the quarter ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on our estimates, the implied fair value of our reporting unit exceeded its carrying value by 15% , 3% , and 14% at the respective measurement dates of March 31, 2016, June 30, 2016 and December 31, 2016. Therefore no additional impairment loss was recorded for the year ended December 31, 2016 . Based on evaluation of qualitative factors, we determined that the goodwill impairment was 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. 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 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 was appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium was 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, 2016 , the net carrying value of this contract was $7.9 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. (i) 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. (j) 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, 2016 or 2015 . (k) 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, 2016 and 2015 , 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: 2016 2015 2014 Mieco, Inc 12% 20% —% ConocoPhillips 11% 7% —% Marathon Oil Company 3% 7% 12% Anadarko Petroleum Corporation 2% 2% 19% Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions. (l) 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. (m) Price and Interest Rate Risk Management Activities: We have historically entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 5) 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 2016 , 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 entered 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 since specific hedge accounting criteria are not met. Gains or losses on derivative contracts 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. 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 fr |
Chapter 11 Proceedings
Chapter 11 Proceedings | 12 Months Ended |
Dec. 31, 2016 | |
Chapter 11 Proceedings [Abstract] | |
Chapter 11 Proceedings | Chapter 11 Proceedings On February 1, 2017 (the “Chapter 11 Filing Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. See Note 2 for a discussion of the Chapter 11 Proceedings (as defined in Note 2). Chapter 11 Proceedings Commencement of Bankruptcy Cases On February 1, 2017 , the Company and certain subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the Chapter 11 Cases under the caption “In re Vanguard Natural Resources, LLC, et al.” The subsidiary Debtors in the Chapter 11 Cases are VNRF; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUDC II; ERAP; ERAP II; EAC; and EOC. No trustee has been appointed and the Company will continue to manage itself and its affiliates and operate their businesses as “debtors-in-possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The Company expects to continue its operations without interruption during the pendency of the Chapter 11 Cases. To assure ordinary course operations, the Debtors secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize the Debtors to maintain their existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. Restructuring Support Agreement Prior to the filing of the Petitions, on February 1, 2017, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) certain holders (the “Consenting 2020 Noteholders”) constituting approximately 52% of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”); (ii) certain holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders) constituting approximately 10% of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the “Consenting Second Lien Noteholders” and, together with the Consenting Senior Noteholders, the “Restructuring Support Parties”) constituting approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”). The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases. The Restructuring Transactions will be financed by (i) use of cash collateral, (ii) the proposed DIP Credit Agreement (as described below), (iii) a fully committed $19.25 million equity investment (the “Second Lien Investment”) by the Consenting Second Lien Noteholders and (iv) a $255.75 million rights offering (the “Senior Note Rights Offering”) that is fully backstopped by the Consenting Senior Noteholders. Certain principal terms of the Plan are outlined below: • Allowed claims (“First Lien Claims”) under the Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”) will be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and may be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims will participate in a new Company $1.1 billion reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by some or all of the lenders under the Reserve-Based Credit Facility. • Allowed Second Lien Claims will receive new notes in the current principal amount of approximately $75.6 million , which shall be substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate. • Each holder of an allowed Senior Note Claim shall receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering. • If the Plan is accepted by the classes of general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units will receive their pro rata share of (a) 3% of the New Equity Interests and (b) three -year warrants for 3% of the New Equity Interests. • The Plan will provide for the $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims will execute a backstop commitment agreement whereby they will agree to fully backstop the Senior Note Rights Offering. • The Plan will provide for the Second Lien Investors to purchase $19.25 million in New Equity Interests at a 25% discount to the Company’s total enterprise value. The Plan will provide for the establishment of a customary management incentive plan at the Company under which 10% of the New Equity Interests will be reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities. The Plan will provide for releases of specified claims held by the Debtors, the Restructuring Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions. The Restructuring Support Agreement obligates the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan. The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. The Restructuring Support Agreement is subject to termination if the effective date of the Plan has not occurred within 150 days of the filing of the Petitions. There can be no assurances that the Restructuring Transactions will be consummated. The Administrative Agent (as defined in the Restructuring Agreement) under the Reserve-Based Credit Facility and the financial institutions party thereto (the “First Lien Lenders”) have not executed the Restructuring Support Agreement, and the New Facility will be subject to the approval of the Administrative Agent and First Lien Lenders in all respects. The Company and the Restructuring Support Parties expect to engage with the First Lien Lenders in an effort to agree upon mutually acceptable terms of the New Facility. Debtor-in-Possession Financing In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The proposed DIP Credit Agreement, if approved by the Bankruptcy Court, contains the following terms: • a revolving credit facility in the aggregate amount of up to $50.0 million , and $15.0 million available on an interim basis; • proceeds of the DIP Credit Agreement may be used by the DIP Borrower to (i) pay certain costs and expenses related to the Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court; • the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court has not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement; • interest will accrue at a rate per year equal to the LIBOR rate plus 5.50% ; • in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the DIP Credit Agreement, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid; • the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion; • the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and • the DIP Credit Agreement is subject to customary covenants, prepayment events, events of default and other provisions. The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion. Acceleration of Debt Obligations The commencement of the Chapter 11 Cases described above constitutes an event of default that accelerated the Debtors’ obligations under the following debt instruments (the “Debt Instruments”). Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code. • $1.25 billion in unpaid principal and approximately $0.2 million of undrawn letters of credit, plus interest, fees, and other expenses arising under or in connection with the Reserve-Based Credit Facility; • $51.12 million in unpaid principal, plus interest, fees, and other expenses, arising under or in connection with the Senior Notes due 2019 issued pursuant to that certain Indenture, dated as of May 27, 2011, as amended, by and among the Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the guarantors named therein, and U.S. Bank, National Association, as indenture trustee. VO became the issuer of the Senior Notes due 2019 pursuant to the Fourth Supplemental Indenture effective as of October 8, 2015, among VO, the Subsidiary Guarantors named therein, as guarantors and U.S. Bank, National Association. Wilmington Trust, National Association, is the successor indenture trustee to the Senior Notes due 2019. • $381.83 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Senior Notes due 2020 issued pursuant to that certain Indenture, dated as of April 4, 2012, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. UMB Bank, N.A., is the successor indenture trustee to the Senior Notes due 2020. • $75.63 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Second Lien Notes issued pursuant to that certain Indenture, dated as of February 10, 2016, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. The Delaware Trust Company is the successor indenture trustee to the Second Lien Notes. The commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 are classified as current in the accompanying consolidated balance sheet as of December 31, 2016. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures 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 4), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below. 2016 Acquisition and Divestitures In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.9 million . As part of the acquisition, Vanguard also acquired the seller’s rights as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. In May 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $270.5 million (the “SCOOP/STACK Divestiture”). The Company used $268.4 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale. During the year ended December 31, 2016 , we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $28.2 million . All cash proceeds received from the sales of these properties were used to reduce borrowings under our Reserve-Based Credit Facility. The SCOOP/STACK Divestiture and the sale of other oil and natural properties did not significantly alter the relationship between capitalized costs and proved reserves. As such, no gain or loss on sales of oil and natural were recognized and the sales proceeds were treated as an adjustment to the cost of the properties. 2015 Acquisitions and Mergers 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 based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. 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 54,437 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 148,048 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 13,746 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable assets acquired 599,064 Bargain Purchase Gain $ (35,838 ) 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. During the year ended December 31, 2016 , Vanguard made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts that existed as of the merger date. As a result, the bargain purchase gain was reduced by $5.0 million . This adjustment is included in the net loss on acquisition of oil and natural gas properties for the year ended December 31, 2016. 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. The asset exchange transaction had 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 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 . Pro Forma Operating Results (Unaudited) In accordance with ASC Topic 805, presented below are unaudited pro forma results for the years ended December 31, 2016 , 2015 and 2014 which reflect the effect on our consolidated results of operations as if (i) the SCOOP/STACK Divestiture completed in 2016 had occurred on January 1, 2015 , (ii) all our acquisitions in 2015 had occurred on January 1, 2014 and (iii) all our acquisitions in 2014 had occurred on January 1, 2013. 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 during 2015 and 2014, and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, adjusted for 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 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, 2016 2015 2014 (in thousands, except per unit amounts) (Pro forma) Total revenues $ 327,066 $ 746,770 $ 1,430,710 Net loss attributable to Common and Class B unitholders $ (847,779 ) $ (2,119,416 ) $ (66,405 ) Net loss attributable to Common and Class B unitholders, per unit: Basic and diluted $ (6.46 ) $ (16.30 ) $ (0.53 ) The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands): Year Ended December 31, 2016 2015 (in thousands) Revenues $ 17,542 $ 57,794 Excess of revenues over direct operating expenses $ 5,932 $ 19,788 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 2016 , 2015 and 2014 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, 2016 2015 2014 (in thousands) LRE Acquisition Revenues $ 46,609 $ 13,083 $ — Excess of revenues over direct operating expenses $ 25,997 $ 6,029 $ — Eagle Rock Acquisition Revenues $ 51,307 $ 23,005 $ — Excess of revenues over direct operating expenses $ 27,495 $ 15,112 $ — Pinedale Acquisition Revenues $ 76,931 $ 84,934 $ 139,908 Excess of revenues over direct operating expenses $ 50,183 $ 56,672 $ 107,934 Piceance Acquisition Revenues $ 30,004 $ 37,767 $ 22,642 Excess of revenues over direct operating expenses $ 19,612 $ 18,427 $ 15,234 All other acquisitions Revenues $ 20,989 $ 36,952 $ 25,989 Excess of revenues over direct operating expenses $ 9,328 $ 20,638 $ 18,450 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our financing arrangements consisted of the following: Amount Outstanding December 31, Description Interest Rate Maturity Date 2016 2015 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,269,000 $ 1,688,000 Senior Notes due 2023 7.00% (2) February 15, 2023 75,634 — Senior Notes due 2020 7.875% (2) April 1, 2020 381,830 550,000 Senior Notes due 2019 8.375% (3) June 1, 2019 51,120 51,120 Lease Financing Obligations 4.16% August 10, 2020 (4) 20,167 24,668 Unamortized discount on Senior Notes (13,167 ) (17,651 ) Unamortized deferred financing costs (5) (11,072 ) (13,705 ) Total Debt $ 1,773,512 $ 2,282,432 Less: Long-term debt classified as current (6) (1,753,345 ) — Current portion (4,692 ) (4,501 ) Total long-term debt $ 15,475 $ 2,277,931 (1) Variable interest rate was 3.11% and 2.90% at December 31, 2016 and 2015 , respectively. (2) Effective interest rate is 8.0% at at December 31, 2016 and 2015 . (3) Effective interest rate is 21.45% at December 31, 2016 and 2015 . (4) The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021. (5) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity (deficit). (6) As a result of our Chapter 11 filing, we have classified our debt under our Reserve-Based Credit Facility and Senior Notes as current at December 31, 2016. Acceleration of Debt Obligations As previously discussed in Note 2. Chapter 11 Proceedings , the commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes, all of which we describe in further detail below. Accordingly, all amounts due under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 are classified as current in the accompanying consolidated balance sheet as of December 31, 2016. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Senior Secured Reserve-Based Credit Facility The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provided a maximum credit facility of $3.5 billion and a borrowing base of $1.1 billion (the “Reserve-Based Credit Facility”). As of December 31, 2016 there were approximately $1.27 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $169.2 million under the Reserve-Based Credit Facility. In May 2016, the lenders party to the Credit Agreement (the “First Lien Lenders”) decreased the Company’s borrowing base from $1.78 billion to $1.325 billion resulting in a borrowing base deficiency of approximately $103.5 million . The Company made monthly payments of $17.5 million through September 2016. On September 30, 2016, the Company entered into a waiver (the “Waiver”) to its Credit Agreement, in which the lenders thereto (the “First Lien Lenders”) agreed, among other things, subject to certain conditions, to waive any event of default, so long as the payment was made within the 30-day grace period, resulting from the Company’s election not to make the approximately $15.0 million semi-annual interest payment due on October 3, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 (defined below). Pursuant to the Waiver, the First Lien Lenders agreed that the Company’s decision to take advantage of the applicable grace period under the indenture governing the Senior Notes due 2020 would not constitute an event of default under the Credit Agreement. A failure to pay interest on the Senior Notes due 2020 following the expiration of the 30-day grace period would have resulted in events of default under the Credit Agreement and the indenture governing the Senior Secured Second Lien Notes (defined below), which would have entitled the trustee under the indenture governing the Senior Secured Second Lien Notes and the First Lien Lenders to declare all obligations thereunder to be immediately due and payable. The Company made the $15.1 million semi-annual interest payment with respect to its Senior Notes due 2020 on October 26, 2016. On October 26, 2016, the Company entered into the Limited Waiver and Eleventh Amendment to the Credit Agreement. Pursuant to the Waiver and Eleventh Amendment, the First Lien Lenders agreed, among other things, subject to certain conditions, to waive any events of default resulting from the Company’s inability to maintain liquidity in excess of $50.0 million , giving pro forma effect to the Company’s payments of (i) the $15.0 million semi-annual interest payment due on October 1, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 and (ii) the approximately $2.1 million semi-annual interest payment due on December 1, 2016 on approximately $51.1 million in aggregate principal amount of Senior Notes due 2019. In conjunction with the Waiver and Eleventh Amendment, the Company monetized certain of its outstanding commodity price hedge agreements and used the proceeds along with cash on hand first to pre-pay the First Lien Lenders (i) $29.3 million , representing the remaining outstanding borrowing base deficiency resulting from the Company’s borrowing base redetermination in May 2016 and (ii) $37.5 million , which was applied as the first required monthly payment to the Company’s new borrowing base deficiency resulting from the November 2016 borrowing base redetermination discussed below. Also, the Company pledged to the First Lien Lenders certain unencumbered midstream assets as collateral as well as agreed to pay 100% of the net cash proceeds from any asset sale, swap or hedge monetization or other disposition to the First Lien Lenders. The borrowing base may be further reduced as a result of such disposition to the extent of the attributed value of such asset to the borrowing base. Furthermore, any incurrence of second lien debt will require the Company to prepay the First Lien Lenders equal to the net cash proceeds received by the Company from any second lien financing. On November 3, 2016, the Company completed its semi-annual redetermination of its borrowing base, resulting in a reduction from $1.325 billion to $1.1 billion . After consideration of the first $37.5 million deficiency payment already having been made pursuant to entering into the Waiver and Eleventh Amendment on October 26, 2016, the Company was scheduled to repay the remaining borrowing base deficiency of $187.5 million in five equal monthly installments of $37.5 million beginning in January 2017. On January 3, 2017, the Company paid the second $37.5 million deficiency payment installment under the Reserve-Based Credit Facility. Letters of Credit At December 31, 2016 , we had unused irrevocable standby letters of credit of approximately $0.2 million . The letters are being maintained as security related to the issuance of oil and gas well permits to recover potential costs of repairs, modification, or construction to remedy damages to properties caused by the operator. 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. 8.375% Senior Notes Due 2019 At December 31, 2016 , we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with 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 our existing subsidiaries, all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”). Prior to the Eagle Rock Merger, the parties to the indenture executed a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default with respect to the Senior Notes due 2019. 7.875% Senior Notes Due 2020 At December 31, 2016 , we had $381.8 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. 7.0% Senior Secured Second Lien Notes Due 2023 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. The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for year ended December 31, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million . 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, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price and Interest Rate Risk Management Activities | Price and Interest Rate Risk Management Activities Commodity Derivatives Histrically, 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. In October and December 2016, we monetized substantially all of our commodity and interest rate hedges with net proceeds totaling $54.0 million . We used the net proceeds from the hedge settlements to make the deficiency payments under our Reserve-Based Credit Facility. 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, 2016 , the Company had the following open interest rate derivative contract (in thousands): Notional Amount Fixed LIBOR Rate Period: January 1, 2017 to February 16, 2017 $ 75,000 1.73 % 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, 2016 Derivative Liabilities: Amount Presented in the Consolidated Balance Sheet Interest rate derivative contract $ (125 ) Total derivative instruments $ (125 ) December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 ) 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 4 for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. As of December 31, 2016 , we only had one counterparty related to our interest rate derivative. 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, 2016 , 2015 and 2014 is as follows: 2016 2015 2014 (in thousands) Derivative asset at January 1, net $ 316,691 $ 220,734 $ 66,711 Purchases Fair value of derivatives acquired — 195,273 (1,344 ) Premiums and fees paid or deferred for derivative contracts during the period (2,444 ) 7,126 — Net gains (losses) on commodity and interest rate derivative contracts (46,939 ) 169,569 161,519 Settlements Net cash settlements received on matured commodity derivative contracts (226,876 ) (211,723 ) (10,187 ) Net cash settlements paid on matured interest rate derivative contracts 13,398 5,227 4,035 Termination of derivative contracts (53,955 ) (69,515 ) — Derivative asset (liability) at December 31, net $ (125 ) $ 316,691 $ 220,734 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , the fair value of our Senior Notes due 2020 was estimated to be $225.3 million , our Senior Notes due 2019 was estimated to be $26.6 million and our Senior Secured Second Lien Notes was estimated to be $ 56.9 million . We consider the inputs to the valuation of our Senior Notes and our Senior Secured Second Lien Notes to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution. Derivative instruments. As previously discussed, we monetized all of our commodity hedges and substantially all of our interest rate hedges. As of December 31, 2016, we have one remaining interest rate swap derivative contract which expires in February 2017. As of December 31, 2015, our commodity derivative instruments consisted of fixed-price swaps, basis swaps, call options sold, swaptions, put options sold, call spreads, call options, put options, three-way collars 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-swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value 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 estimate for these derivative instruments as a Level 2 input. We estimate the value 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 valuation 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 estimate 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, 2016 Fair Value Measurements Using Level 2 Assets/Liabilities at Fair Value (in thousands) Liabilities: Interest rate derivative contract $ (125 ) $ (125 ) Total derivative instruments $ (125 ) $ (125 ) December 31, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value (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 ) 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: 2016 2015 (in thousands) Unobservable inputs at January 1, $ (5,933 ) $ (6,470 ) Total gains 11,838 5,151 Settlements (5,905 ) (4,614 ) Unobservable inputs at December 31, $ — $ (5,933 ) Change in fair value included in earnings related to derivatives still held as of December 31, $ — $ (2,925 ) 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. We consider the fair value estimate for goodwill as a Level 3 input, as the valuation includes inputs and assumptions that are less observable or require greater estimation. At the respective measurement dates of March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016 , the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test at these interim dates. 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 the respective measurement date 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 interim goodwill impairment test, we recorded a non-cash goodwill impairment loss of $252.7 million during the quarter ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on our estimates, the implied fair value of our reporting unit exceeded its carrying value at the measurement dates of March 31, 2016, June 30, 2016, and December 31, 2016, therefore no additional impairment loss was recorded for the year ended December 31, 2016 . Based on evaluation of qualitative factors, we determined that the goodwill impairment was 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. 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. 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 7, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the years ended December 31, 2016 and 2015 , 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 $0.7 million and $90.9 million , respectively, at fair value. We also recorded a $1.3 million and a $22.3 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, 2016 and 2015 , 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, 2016 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The asset retirement obligations as of December 31 , 2016 and 2015, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31 , 2016 were as follows: 2016 2015 (in thousands) Asset retirement obligation at January 1, $ 271,456 $ 149,062 Liabilities added during the current period 713 2,699 Liabilities added from the LRE and Eagle Rock Mergers — 88,228 Accretion expense 12,145 10,238 Change in estimate 1,267 22,329 Disposition of properties (10,915 ) (262 ) Retirements (2,230 ) (838 ) Total asset retirement obligation at December 31, 272,436 271,456 Less: current obligations (7,884 ) (9,024 ) Long-term asset retirement obligation at December 31, $ 264,552 $ 262,432 Accretion expense for the years ended December 31, 2016 , 2015 and 2014 was $12.1 million , $10.2 million and $5.9 million , respectively. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2016 and 2015 , we reviewed the actual abandonment costs with previous estimates and, as a result, increased our estimates of future asset retirement obligations by a net $1.3 million and $22.3 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, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Transportation Demand Charges As of December 31, 2016 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to four 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, 2016 . 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) 2017 $ 12,538 2018 11,678 2019 9,661 2020 410 Total $ 34,287 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 2017 is approximately $13.7 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 (i) the LRE Merger, (ii) the Eagle Rock Merger and (iii) our exchange (the “Debt Exchange”) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 4. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion). 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, 2016 | |
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, 2016 and 2015 : 2016 2015 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. 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. All preferred distributions will continue to accumulate and must be paid in full before distributions to common and Class B unitholders can resume. As of December 31, 2016 , dividends in arrears related to our Cumulative Preferred Units were $4.2 million , $11.1 million and $6.9 million , respectively. 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. We repurchased a total of 291,926 units under the common unit buyback program for an aggregate cost of $4.9 million since its inception through December 31, 2015. No units were repurchased during 2016. The following is a summary of the changes in our common units issued during the years ended December 31, 2016 , 2015 and 2014 (in thousands): 2016 2015 2014 Beginning of period 130,477 83,452 78,337 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 cash — 2,430 4,864 Repurchase of units under the common unit buyback program — (157 ) (135 ) Unit-based compensation 532 1,418 386 End of period 131,009 130,477 83,452 There was no change in issued and outstanding Class B units during the years ended December 31, 2016 , 2015 and 2014 . Net Income (Loss) per Common and Class B Unit Basic net income (loss) per common and Class B unit is computed in accordance with ASC Topic 260 “ Earnings Per Share ” (“ASC Topic 260”) by dividing net income (loss) attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income (loss)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 (loss) per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of net income (loss) 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 (loss) per common and Class B unit were as follows (in thousands, except per unit data): 2016 (a) 2015 (a) 2014 Net income (loss) attributable to Common and Class B unitholders $ (841,847 ) $ (1,909,933 ) $ 46,148 Weighted average number of Common and Class B units outstanding - basic 131,323 96,468 82,031 Effect of dilutive securities: Phantom units — — 428 Weighted average number of Common and Class B units outstanding - diluted 131,323 96,468 82,459 Net income (loss) per Common and Class B unit Basic $ (6.41 ) $ (19.80 ) $ 0.56 Diluted $ (6.41 ) $ (19.80 ) $ 0.55 (a) For the years ended December 31, 2016 and 2015 , 3,799,304 and 164,984 phantom units, respectively, 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. 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. 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 2016 First Quarter January $ 0.0300 February 18, 2016 March 1, 2016 March 15, 2016 2015 Fourth Quarter December $ 0.0300 January 20, 2016 February 1, 2016 February 12, 2016 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 |
Unit-Based Compensation
Unit-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Unit-Based Compensation | 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 On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The Amended Agreements were effective January 1, 2016 and the initial term of the Amended Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date. 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, 2016 and 2015, we recognized an accrued liability of $0.4 million and $1.1 million , respectively, related to the performance-based bonus award. Total compensation expense related to these arrangements of $1.8 million , $1.1 million and $1.4 million was recorded for the years ended December 31, 2016 , 2015 and 2014 , respectively, 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. Unit Grants In January 2016, the executives were granted a total of 2,255,033 phantom units in accordance with the Amended Agreements. Also, during the year ended December 31, 2016 , our three independent board members were granted a total of 125,838 phantom units which will vest one year from the date of grant. In addition, VNR employees were granted 1,331,579 phantom units under the VNR LTIP which will vest three years from the date of grant and a VNR employee was granted a total of 7,500 restricted units under the VNR LTIP of which one-third will vest on each one-year anniversary of the date of grant so long as the employee remains continuously employed with the Company. The phantom units include a tandem grant of DERs. As of December 31, 2016 , 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, 2015 976,348 $ 18.29 Granted 7,500 $ 3.11 Forfeited (60,971 ) $ 14.36 Vested (275,093 ) $ 17.00 Non-vested units at December 31, 2016 647,784 $ 19.14 The weighted average grant-date fair value of restricted units granted was $15.17 and $29.02 during the years ended December 31, 2015 and 2014 , respectively. At December 31, 2016 , there was approximately $4.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately one year. Our Consolidated Statements of Operations reflects non-cash compensation related to restricted unit grants of $5.4 million , $16.9 million and $10.7 million in the Selling, general and administrative expenses line item for the years ended December 31, 2016 , 2015 and 2014 , respectively. Phantom Unit Grants As of December 31, 2016 , 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, 2015 203,221 $ 20.99 Granted 3,712,450 $ 2.56 Forfeited (164,507 ) $ 1.85 Vested (122,635 ) $ 22.23 Non-vested units at December 31, 2016 3,628,529 $ 2.96 We did not grant any phantom units during the years ended December 31, 2015 and 2014. At December 31, 2016 , there was approximately $6.7 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately one year. Compensation expense related to phantom units granted to executive officers, board members and employees of $4.8 million , $1.7 million and $1.0 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, 2016 , 2015 , and 2014 , respectively. |
Shelf Registration Statements
Shelf Registration Statements | 12 Months Ended |
Dec. 31, 2016 | |
Shelf Registration Statement [Abstract] | |
Shelf Registration Statement | Shelf Registration Statements Prior to the entry into the Chapter 11 Cases, the Company had an effective universal shelf registration statement on Form S-3, as amended (File No. 333-210329), filed with the SEC, under which the Company registered an indeterminate amount of common units, Preferred Units, debt securities and guarantees of debt securities. The Company also had on file with the SEC a post-effective shelf registration statement on Form S-3, as amended (File No. 333-207357), under which the Company registered up to 14,593,606 common units. The Company is no longer eligible to offer or sell any of its securities pursuant to the shelf registration statements on Form S-3. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | 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. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements. |
Chapter 11 Proceedings | Chapter 11 Proceedings On February 1, 2017 (the “Chapter 11 Filing Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. See Note 2 for a discussion of the Chapter 11 Proceedings (as defined in Note 2). Chapter 11 Proceedings Commencement of Bankruptcy Cases On February 1, 2017 , the Company and certain subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the Chapter 11 Cases under the caption “In re Vanguard Natural Resources, LLC, et al.” The subsidiary Debtors in the Chapter 11 Cases are VNRF; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUDC II; ERAP; ERAP II; EAC; and EOC. No trustee has been appointed and the Company will continue to manage itself and its affiliates and operate their businesses as “debtors-in-possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The Company expects to continue its operations without interruption during the pendency of the Chapter 11 Cases. To assure ordinary course operations, the Debtors secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize the Debtors to maintain their existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. Restructuring Support Agreement Prior to the filing of the Petitions, on February 1, 2017, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) certain holders (the “Consenting 2020 Noteholders”) constituting approximately 52% of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”); (ii) certain holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders) constituting approximately 10% of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the “Consenting Second Lien Noteholders” and, together with the Consenting Senior Noteholders, the “Restructuring Support Parties”) constituting approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”). The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases. The Restructuring Transactions will be financed by (i) use of cash collateral, (ii) the proposed DIP Credit Agreement (as described below), (iii) a fully committed $19.25 million equity investment (the “Second Lien Investment”) by the Consenting Second Lien Noteholders and (iv) a $255.75 million rights offering (the “Senior Note Rights Offering”) that is fully backstopped by the Consenting Senior Noteholders. Certain principal terms of the Plan are outlined below: • Allowed claims (“First Lien Claims”) under the Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”) will be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and may be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims will participate in a new Company $1.1 billion reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by some or all of the lenders under the Reserve-Based Credit Facility. • Allowed Second Lien Claims will receive new notes in the current principal amount of approximately $75.6 million , which shall be substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate. • Each holder of an allowed Senior Note Claim shall receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering. • If the Plan is accepted by the classes of general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units will receive their pro rata share of (a) 3% of the New Equity Interests and (b) three -year warrants for 3% of the New Equity Interests. • The Plan will provide for the $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims will execute a backstop commitment agreement whereby they will agree to fully backstop the Senior Note Rights Offering. • The Plan will provide for the Second Lien Investors to purchase $19.25 million in New Equity Interests at a 25% discount to the Company’s total enterprise value. The Plan will provide for the establishment of a customary management incentive plan at the Company under which 10% of the New Equity Interests will be reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities. The Plan will provide for releases of specified claims held by the Debtors, the Restructuring Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions. The Restructuring Support Agreement obligates the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan. The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. The Restructuring Support Agreement is subject to termination if the effective date of the Plan has not occurred within 150 days of the filing of the Petitions. There can be no assurances that the Restructuring Transactions will be consummated. The Administrative Agent (as defined in the Restructuring Agreement) under the Reserve-Based Credit Facility and the financial institutions party thereto (the “First Lien Lenders”) have not executed the Restructuring Support Agreement, and the New Facility will be subject to the approval of the Administrative Agent and First Lien Lenders in all respects. The Company and the Restructuring Support Parties expect to engage with the First Lien Lenders in an effort to agree upon mutually acceptable terms of the New Facility. Debtor-in-Possession Financing In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The proposed DIP Credit Agreement, if approved by the Bankruptcy Court, contains the following terms: • a revolving credit facility in the aggregate amount of up to $50.0 million , and $15.0 million available on an interim basis; • proceeds of the DIP Credit Agreement may be used by the DIP Borrower to (i) pay certain costs and expenses related to the Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court; • the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court has not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement; • interest will accrue at a rate per year equal to the LIBOR rate plus 5.50% ; • in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the DIP Credit Agreement, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid; • the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion; • the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and • the DIP Credit Agreement is subject to customary covenants, prepayment events, events of default and other provisions. The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion. Acceleration of Debt Obligations The commencement of the Chapter 11 Cases described above constitutes an event of default that accelerated the Debtors’ obligations under the following debt instruments (the “Debt Instruments”). Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code. • $1.25 billion in unpaid principal and approximately $0.2 million of undrawn letters of credit, plus interest, fees, and other expenses arising under or in connection with the Reserve-Based Credit Facility; • $51.12 million in unpaid principal, plus interest, fees, and other expenses, arising under or in connection with the Senior Notes due 2019 issued pursuant to that certain Indenture, dated as of May 27, 2011, as amended, by and among the Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the guarantors named therein, and U.S. Bank, National Association, as indenture trustee. VO became the issuer of the Senior Notes due 2019 pursuant to the Fourth Supplemental Indenture effective as of October 8, 2015, among VO, the Subsidiary Guarantors named therein, as guarantors and U.S. Bank, National Association. Wilmington Trust, National Association, is the successor indenture trustee to the Senior Notes due 2019. • $381.83 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Senior Notes due 2020 issued pursuant to that certain Indenture, dated as of April 4, 2012, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. UMB Bank, N.A., is the successor indenture trustee to the Senior Notes due 2020. • $75.63 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Second Lien Notes issued pursuant to that certain Indenture, dated as of February 10, 2016, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. The Delaware Trust Company is the successor indenture trustee to the Second Lien Notes. The commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 are classified as current in the accompanying consolidated balance sheet as of December 31, 2016. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. |
New Pronouncement Issued But Not Yet Adopted | New Pronouncements Issued But Not Yet Adopted: In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five-step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation and begun contract review and documentation. The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catch-up transition method). The Company is currently evaluating the available adoption methods. 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. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16, pursuant to Staff Announcements at the March 3, EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU provide clarifying guidance in certain narrow areas and adds some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on the calculation or presentation of our results of operations, cash flows, or financial position. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) to simplify the accounting for goodwill impairment. The guidance eliminates the need for Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The new standard also eliminates the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. The revised guidance will be applied prospectively, and is effective for public companies for fiscal years beginning January 1, 2020. Early adoption is permitted for any impairment tests performed after January 1, 2017. The Company plans to early adopt this guidance and will apply it prospectively for all goodwill impairment tests performed on or after January 1, 2017. As a result of adopting this guidance, we do not expect to record a goodwill impairment in the near term due to the negative carrying value of the reporting unit at December 31, 2016. |
Cash Equivalents | 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 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 | 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 | 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, 2016 of $494.3 million . Such impairment was recognized during the first, second and fourth quarters of 2016 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2016 $ 207,764 $2.41 $46.16 Second quarter 2016 $ 157,894 $2.24 $42.91 Third quarter 2016 $ — $2.29 $41.48 Fourth quarter 2016 $ 128,612 $2.47 $42.60 Total $ 494,270 The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2016 were the reduction in our proved reserves quantities due to the reclassification of our proved undeveloped reserves to contingent resources due to uncertainties surrounding the availability of financing that would be necessary to develop these reserves and the impact of sustained lower commodity prices. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices. Such impairment was recorded during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ 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 affecting the 2015 impairment 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. 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. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas property costs 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 | 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 2016 , 2015 and 2014 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 also performed interim impairment tests at each quarter end, commencing with the quarter ended December 31, 2014. At each measurement date, if the Company was required to perform 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 included: (i) observable forward prices for commodities at the respective measurement date and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. At the respective measurement dates of March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016 , the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test at these interim dates. Based on the results of the the second step of the interim goodwill impairment test, we recorded a non-cash goodwill impairment loss of $252.7 million during the quarter ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on our estimates, the implied fair value of our reporting unit exceeded its carrying value by 15% , 3% , and 14% at the respective measurement dates of March 31, 2016, June 30, 2016 and December 31, 2016. Therefore no additional impairment loss was recorded for the year ended December 31, 2016 . Based on evaluation of qualitative factors, we determined that the goodwill impairment was 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. 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 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 was appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium was 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, 2016 , the net carrying value of this contract was $7.9 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 | 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 | 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. |
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, 2016 or 2015 . |
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, 2016 and 2015 , 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 | 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 | Price and Interest Rate Risk Management Activities: We have historically entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 5) 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 2016 , 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 entered 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 since specific hedge accounting criteria are not met. Gains or losses on derivative contracts 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. 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. As of December 31, 2016, we have no commodity derivative contracts in place. |
Income Taxes | 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 $2.0 billion and $1.3 billion at December 31, 2016 and 2015 , 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 $0.3 million and $0.2 million as of December 31, 2016 and 2015 , respectively, and a deferred tax asset of $2.0 million and $0.5 million as of December 31, 2016 and 2015 , respectively. Tax benefits of $1.3 million , $0.3 million and $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2016 , 2015 , and 2014 , 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, 2016 and 2015, the Company recorded a deferred tax liability of $37.6 million and $39.4 million , respectively, related to these C Corporations, which is included in the other long-term liabilities line item in the Consolidated Balance Sheets. The Company also recorded a net deferred tax asset at December 31, 2016 and 2015 of $2.2 million from the Eagle Rock Merger related to the book/tax differences in property, plant and equipment and hedging transactions, which is included in the other assets line item in the Consolidated Balance Sheets. In assessing the realizability of net deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2016 , based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of the deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. |
Prior Year Financial Statement Presentation | Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Annual Report on Form 10-K. Please read Note 4. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Schedule of impairment of oil and natural gas properties | Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2016 $ 207,764 $2.41 $46.16 Second quarter 2016 $ 157,894 $2.24 $42.91 Third quarter 2016 $ — $2.29 $41.48 Fourth quarter 2016 $ 128,612 $2.47 $42.60 Total $ 494,270 | 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: 2016 2015 2014 Mieco, Inc 12% 20% —% ConocoPhillips 11% 7% —% Marathon Oil Company 3% 7% 12% Anadarko Petroleum Corporation 2% 2% 19% |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 2014 (in thousands, except per unit amounts) (Pro forma) Total revenues $ 327,066 $ 746,770 $ 1,430,710 Net loss attributable to Common and Class B unitholders $ (847,779 ) $ (2,119,416 ) $ (66,405 ) Net loss attributable to Common and Class B unitholders, per unit: Basic and diluted $ (6.46 ) $ (16.30 ) $ (0.53 ) The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands): Year Ended December 31, 2016 2015 (in thousands) Revenues $ 17,542 $ 57,794 Excess of revenues over direct operating expenses $ 5,932 $ 19,788 |
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 2016 , 2015 and 2014 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, 2016 2015 2014 (in thousands) LRE Acquisition Revenues $ 46,609 $ 13,083 $ — Excess of revenues over direct operating expenses $ 25,997 $ 6,029 $ — Eagle Rock Acquisition Revenues $ 51,307 $ 23,005 $ — Excess of revenues over direct operating expenses $ 27,495 $ 15,112 $ — Pinedale Acquisition Revenues $ 76,931 $ 84,934 $ 139,908 Excess of revenues over direct operating expenses $ 50,183 $ 56,672 $ 107,934 Piceance Acquisition Revenues $ 30,004 $ 37,767 $ 22,642 Excess of revenues over direct operating expenses $ 19,612 $ 18,427 $ 15,234 All other acquisitions Revenues $ 20,989 $ 36,952 $ 25,989 Excess of revenues over direct operating expenses $ 9,328 $ 20,638 $ 18,450 |
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 54,437 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 148,048 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 13,746 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable assets acquired 599,064 Bargain Purchase Gain $ (35,838 ) |
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 ) |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Financing Arrangements | Our financing arrangements consisted of the following: Amount Outstanding December 31, Description Interest Rate Maturity Date 2016 2015 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,269,000 $ 1,688,000 Senior Notes due 2023 7.00% (2) February 15, 2023 75,634 — Senior Notes due 2020 7.875% (2) April 1, 2020 381,830 550,000 Senior Notes due 2019 8.375% (3) June 1, 2019 51,120 51,120 Lease Financing Obligations 4.16% August 10, 2020 (4) 20,167 24,668 Unamortized discount on Senior Notes (13,167 ) (17,651 ) Unamortized deferred financing costs (5) (11,072 ) (13,705 ) Total Debt $ 1,773,512 $ 2,282,432 Less: Long-term debt classified as current (6) (1,753,345 ) — Current portion (4,692 ) (4,501 ) Total long-term debt $ 15,475 $ 2,277,931 (1) Variable interest rate was 3.11% and 2.90% at December 31, 2016 and 2015 , respectively. (2) Effective interest rate is 8.0% at at December 31, 2016 and 2015 . (3) Effective interest rate is 21.45% at December 31, 2016 and 2015 . (4) The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021. (5) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity (deficit). (6) As a result of our Chapter 11 filing, we have classified our debt under our Reserve-Based Credit Facility and Senior Notes as current at December 31, 2016. |
Price and Interest Rate Risk 24
Price and Interest Rate Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Interest Rate Derivative Contracts | At December 31, 2016 , the Company had the following open interest rate derivative contract (in thousands): Notional Amount Fixed LIBOR Rate Period: January 1, 2017 to February 16, 2017 $ 75,000 1.73 % |
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, 2016 Derivative Liabilities: Amount Presented in the Consolidated Balance Sheet Interest rate derivative contract $ (125 ) Total derivative instruments $ (125 ) December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 ) |
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, 2016 , 2015 and 2014 is as follows: 2016 2015 2014 (in thousands) Derivative asset at January 1, net $ 316,691 $ 220,734 $ 66,711 Purchases Fair value of derivatives acquired — 195,273 (1,344 ) Premiums and fees paid or deferred for derivative contracts during the period (2,444 ) 7,126 — Net gains (losses) on commodity and interest rate derivative contracts (46,939 ) 169,569 161,519 Settlements Net cash settlements received on matured commodity derivative contracts (226,876 ) (211,723 ) (10,187 ) Net cash settlements paid on matured interest rate derivative contracts 13,398 5,227 4,035 Termination of derivative contracts (53,955 ) (69,515 ) — Derivative asset (liability) at December 31, net $ (125 ) $ 316,691 $ 220,734 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis | December 31, 2016 Fair Value Measurements Using Level 2 Assets/Liabilities at Fair Value (in thousands) Liabilities: Interest rate derivative contract $ (125 ) $ (125 ) Total derivative instruments $ (125 ) $ (125 ) December 31, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value (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 ) |
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: 2016 2015 (in thousands) Unobservable inputs at January 1, $ (5,933 ) $ (6,470 ) Total gains 11,838 5,151 Settlements (5,905 ) (4,614 ) Unobservable inputs at December 31, $ — $ (5,933 ) Change in fair value included in earnings related to derivatives still held as of December 31, $ — $ (2,925 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
Changes in Asset Retirement Obligations | The asset retirement obligations as of December 31 , 2016 and 2015, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31 , 2016 were as follows: 2016 2015 (in thousands) Asset retirement obligation at January 1, $ 271,456 $ 149,062 Liabilities added during the current period 713 2,699 Liabilities added from the LRE and Eagle Rock Mergers — 88,228 Accretion expense 12,145 10,238 Change in estimate 1,267 22,329 Disposition of properties (10,915 ) (262 ) Retirements (2,230 ) (838 ) Total asset retirement obligation at December 31, 272,436 271,456 Less: current obligations (7,884 ) (9,024 ) Long-term asset retirement obligation at December 31, $ 264,552 $ 262,432 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 . 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) 2017 $ 12,538 2018 11,678 2019 9,661 2020 410 Total $ 34,287 |
Members' Equity (Deficit) and28
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Cumulative Preferred Units | The following table summarizes the Company’s Cumulative Preferred Units outstanding at December 31, 2016 and 2015 : 2016 2015 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, 2016 , 2015 and 2014 (in thousands): 2016 2015 2014 Beginning of period 130,477 83,452 78,337 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 cash — 2,430 4,864 Repurchase of units under the common unit buyback program — (157 ) (135 ) Unit-based compensation 532 1,418 386 End of period 131,009 130,477 83,452 |
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 (loss) per common and Class B unit were as follows (in thousands, except per unit data): 2016 (a) 2015 (a) 2014 Net income (loss) attributable to Common and Class B unitholders $ (841,847 ) $ (1,909,933 ) $ 46,148 Weighted average number of Common and Class B units outstanding - basic 131,323 96,468 82,031 Effect of dilutive securities: Phantom units — — 428 Weighted average number of Common and Class B units outstanding - diluted 131,323 96,468 82,459 Net income (loss) per Common and Class B unit Basic $ (6.41 ) $ (19.80 ) $ 0.56 Diluted $ (6.41 ) $ (19.80 ) $ 0.55 (a) For the years ended December 31, 2016 and 2015 , 3,799,304 and 164,984 phantom units, respectively, 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 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 2016 First Quarter January $ 0.0300 February 18, 2016 March 1, 2016 March 15, 2016 2015 Fourth Quarter December $ 0.0300 January 20, 2016 February 1, 2016 February 12, 2016 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 |
Unit-Based Compensation (Tables
Unit-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Status of Non-Vested Restricted Units | As of December 31, 2016 , 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, 2015 976,348 $ 18.29 Granted 7,500 $ 3.11 Forfeited (60,971 ) $ 14.36 Vested (275,093 ) $ 17.00 Non-vested units at December 31, 2016 647,784 $ 19.14 |
Summary of the Status of the Non-Vested Phantom Units | As of December 31, 2016 , 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, 2015 203,221 $ 20.99 Granted 3,712,450 $ 2.56 Forfeited (164,507 ) $ 1.85 Vested (122,635 ) $ 22.23 Non-vested units at December 31, 2016 3,628,529 $ 2.96 |
Description of the Business (De
Description of the Business (Details) | 12 Months Ended |
Dec. 31, 2016operating_areas | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating areas | 10 |
Summary of Significant Accoun31
Summary of Significant Accounting Policies (Basis of Presentation and Principles of Consolidation) (Details) | Dec. 31, 2016 |
Potato Hills Gas Gathering System [Member] | |
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Oil and Natural Gas Properties) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016USD ($)$ / bbl$ / MMBTU | Sep. 30, 2016USD ($)$ / bbl$ / MMBTU | Jun. 30, 2016USD ($)$ / bbl$ / MMBTU | Mar. 31, 2016USD ($)$ / bbl$ / MMBTU | 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, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
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 | $ | $ 128,612 | $ 0 | $ 157,894 | $ 207,764 | $ 484,855 | $ 491,487 | $ 733,365 | $ 132,610 | $ 494,270 | $ 1,842,317 | $ 234,434 | |
Average price of natural gas used in the impairment calculation | $ / MMBTU | 2.47 | 2.29 | 2.24 | 2.41 | 2.62 | 3.11 | 3.44 | 3.91 | 4.36 | |||
Average price of crude oil used in the impairment calculation (per barrel) | $ / bbl | 42.60 | 41.48 | 42.91 | 46.16 | 50.20 | 59.23 | 71.51 | 82.62 | 94.87 |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Other Intangible Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2016 | Mar. 31, 2016 | |
Other Intangible Assets | |||||
Deferred Tax Assets, Net | $ 2,200 | $ 2,200 | |||
Discount rate used in determining limitation of capitalized costs | 10.00% | ||||
Impairment of goodwill | $ 252,676 | 71,425 | $ 0 | ||
Goodwill | $ 253,370 | $ 506,046 | |||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 0.00% | 0.00% | 0.00% | 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 | $ 7,900 |
Summary of Significant Accoun34
Summary of Significant Accounting Policies (Concentrations of Credit Risk) (Details) - institution | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Concentration Risk, Number of Financial Institutions | 1 | 1 | 1 | |
Customer Concentration Risk [Member] | Sales [Member] | Mieco, Inc. [Member] | ||||
Revenue, Major Purchasers | ||||
Major purchasers, percent of sales | 12.00% | 20.00% | 0.00% | |
Customer Concentration Risk [Member] | Sales [Member] | ConocoPhilips [Member] | ||||
Revenue, Major Purchasers | ||||
Major purchasers, percent of sales | 11.00% | 7.00% | 0.00% | |
Customer Concentration Risk [Member] | Sales [Member] | Marathon Oil Company [Member] | ||||
Revenue, Major Purchasers | ||||
Major purchasers, percent of sales | 3.00% | 7.00% | 12.00% | |
Customer Concentration Risk [Member] | Sales [Member] | Anadarko Petroleum Corporation [Member] | ||||
Revenue, Major Purchasers | ||||
Major purchasers, percent of sales | 2.00% | 2.00% | 19.00% |
Summary of Significant Accoun35
Summary of Significant Accounting Policies (Income Taxes) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revised Texas Franchise Tax | |||
Entity Not Subject to Income Taxes, Differences in Bases, Amount | $ 2,000 | $ 1,300 | |
Deferred Tax Liabilities, Other | 37.6 | 39.4 | |
Deferred Tax Assets, Net | 2.2 | 2.2 | |
Texas [Member] | |||
Revised Texas Franchise Tax | |||
Current tax liability | (0.3) | (0.2) | |
Deferred tax asset | 2 | 0.5 | |
Income Tax Expense (Benefit) | $ (1.3) | $ (0.3) | $ 0.6 |
Chapter 11 Proceedings (Commenc
Chapter 11 Proceedings (Commencement of Bankruptcy Cases) (Details) | Feb. 01, 2017 |
Subsequent Event [Member] | |
Petition filing date | Feb. 1, 2017 |
Chapter 11 Proceedings (Restruc
Chapter 11 Proceedings (Restructuring Support Agreement) (Details) | Feb. 01, 2017USD ($) | Dec. 31, 2016 | Feb. 10, 2016 |
Senior Notes due 2020 [Member] | |||
Stated interest rate (in hundredths) | 7.875% | ||
Senior Notes due 2019 [Member] | |||
Stated interest rate (in hundredths) | 8.375% | ||
Subordinated Debt [Member] | |||
Stated interest rate (in hundredths) | 7.00% | ||
Subsequent Event [Member] | |||
Plan of Reorganization, Amount of equity investment commitment | $ 19,250,000 | ||
Plan of Reorganization, Principal Amount of Senior Note Rights Offering | 255,750,000 | ||
Plan of Reorganization, Amount of Prepetition Debt to be Settled From Financing Under the Restructuring Support Agreement | 275,000,000 | ||
Plan of Reorganization, Amount of Debt Securities to be Issued | $ 75,600,000 | ||
Basis Points Increase in Debt Securities Interest Rate | 0.02 | ||
Warrant Exercise Period | 3 years | ||
Discount on New Equity Security Issue Price | 25.00% | ||
Plan of Reorganization, Restructuring Support Agreement effective period | 150 days | ||
Subsequent Event [Member] | Senior Notes due 2020 [Member] | |||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 52.00% | ||
Stated interest rate (in hundredths) | 7.875% | ||
Subsequent Event [Member] | Senior Notes due 2019 [Member] | |||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 10.00% | ||
Stated interest rate (in hundredths) | 8.375% | ||
Subsequent Event [Member] | Subordinated Debt [Member] | |||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 92.00% | ||
Stated interest rate (in hundredths) | 7.00% | ||
Subsequent Event [Member] | Line of Credit, New Facility [Member] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,100,000,000 | ||
Senior Note Holder [Member] | Subsequent Event [Member] | |||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 97.00% | ||
Preferred Unit Holder [Member] | Subsequent Event [Member] | |||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 3.00% |
Chapter 11 Proceedings (Debtor-
Chapter 11 Proceedings (Debtor-in-Possession) (Details) - Subsequent Event [Member] $ in Millions | Feb. 01, 2017USD ($) |
Aggregate financing amount | $ 50 |
Preconfirmation, Debtor-in-Possession Financing, Interim Borrowing Capacity | 15 |
Minimum amount of debtor unrestricted cash and DIP financing unused borrowing | $ 25 |
Debtor-in-Possession Financing [Member] | |
Commitment fee (as a percent) | 1.00% |
Debtor-in-Possession Financing [Member] | London Interbank Offered Rate (LIBOR) [Member] | |
Variable interest rate (as a percent) | 5.50% |
Chapter 11 Proceedings (Acceler
Chapter 11 Proceedings (Acceleration of Debt Obligations) (Details) - USD ($) $ in Thousands | Feb. 01, 2017 | Dec. 31, 2016 | Nov. 03, 2016 | Oct. 26, 2016 | Oct. 03, 2016 | Sep. 30, 2016 | May 26, 2016 | Feb. 10, 2016 | Dec. 31, 2015 |
Unpaid principal amount | $ 1,773,512 | $ 2,282,432 | |||||||
Subordinated Debt [Member] | |||||||||
Unpaid principal amount | $ 75,600 | ||||||||
Subordinated Debt [Member] | Subsequent Event [Member] | |||||||||
Unpaid principal amount | $ 75,630 | ||||||||
Line of Credit [Member] | |||||||||
Unpaid principal amount | 1,270,000 | ||||||||
Undrawn letters of credit | $ 1,100,000 | $ 1,325,000 | $ 1,780,000 | ||||||
Line of Credit [Member] | Subsequent Event [Member] | |||||||||
Unpaid principal amount | 1,250,000 | ||||||||
Senior Notes due 2019 [Member] | |||||||||
Unpaid principal amount | 51,100 | $ 51,100 | |||||||
Senior Notes due 2019 [Member] | Subsequent Event [Member] | |||||||||
Unpaid principal amount | 51,120 | ||||||||
Senior Notes due 2020 [Member] | |||||||||
Unpaid principal amount | $ 381,800 | $ 381,800 | |||||||
Senior Notes due 2020 [Member] | Subsequent Event [Member] | |||||||||
Unpaid principal amount | 381,830 | ||||||||
Standby Letters of Credit [Member] | Line of Credit [Member] | |||||||||
Undrawn letters of credit | $ 200 | ||||||||
Standby Letters of Credit [Member] | Line of Credit [Member] | Subsequent Event [Member] | |||||||||
Undrawn letters of credit | $ 200 |
Acquisitions and Divestitures40
Acquisitions and Divestitures (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions | May 19, 2016 | Jan. 01, 2016 | Oct. 08, 2015 | Oct. 05, 2015 | Jul. 31, 2015 | Sep. 30, 2014 | Aug. 29, 2014 | May 02, 2014 | Jan. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | ||||||||||||
Proceeds from the sale of oil and natural gas properties | $ 298,701 | $ 1,777 | $ 4,973 | |||||||||
Goodwill | 253,370 | $ 506,046 | ||||||||||
Potato Hills Gas Gathering System [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest conveyed | 51.00% | |||||||||||
Business Combination, Consideration Transferred | $ 7,900 | |||||||||||
SCOOP/STACK Divestiture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Proceeds from the sale of oil and natural gas properties | $ 270,500 | |||||||||||
Cash Divested from Deconsolidation | 2,100 | |||||||||||
Series of Individually Immaterial Business Acquisitions [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest conveyed | 75.00% | |||||||||||
Business Combination, Consideration Transferred | $ 11,400 | $ 269,900 | $ 6,800 | 17,700 | ||||||||
Proceeds from the sale of oil and natural gas properties | $ 28,200 | |||||||||||
Effective date of acquisition | Jun. 1, 2014 | Jan. 1, 2014 | ||||||||||
LRE Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Consideration Transferred | $ 413,276 | |||||||||||
Number of shares issued | 15.4 | |||||||||||
Goodwill | $ 156,514 | |||||||||||
Purchase price of acquired entity paid in common equity | $ 123,276 | |||||||||||
Shares issued, closing price | $ 7.98 | |||||||||||
EROC Merger [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Consideration Transferred | $ 415,178 | |||||||||||
Number of shares issued | 27.7 | |||||||||||
Gain on acquisition | $ 35,838 | |||||||||||
Purchase price of acquired entity paid in common equity | $ 258,282 | |||||||||||
Shares issued, closing price | $ 9.31 | |||||||||||
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 | |||||||||||
Line of Credit [Member] | SCOOP/STACK Divestiture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Repayments of Lines of Credit | $ 268,400 |
Acquisitions and Divestitures A
Acquisitions and Divestitures Acquisitions and Divestitures (LRE Merger) (Details) $ / shares in Units, $ in Thousands, shares in Millions | Oct. 05, 2015USD ($)$ / sharesshares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Less: fair value of assets acquired | |||
Goodwill | $ 253,370 | $ 506,046 | |
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 | ||
General Partner [Member] | LRE Merger [Member] | |||
Business Acquisition [Line Items] | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 0 |
Acquisitions and Divestitures42
Acquisitions and Divestitures Acquisitions and Divestitures (Eagle Rock Merger) (Details) - EROC Merger [Member] $ / shares in Units, $ in Thousands | Oct. 08, 2015USD ($)$ / shares | Dec. 31, 2016USD ($) |
Business Acquisition [Line Items] | ||
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio | 0.185 | |
Business Acquisition, Share Price | $ / shares | $ 9.31 | |
Debt extinguished subsequent to the merger | $ 122,300 | |
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment to Bargain Purchase Gain Recognized | $ (5,000) | |
Business Combination, Consideration Transferred [Abstract] | ||
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 | |
Business Combination, Consideration Transferred | 415,178 | |
Amount attributable to liabilities assumed | ||
Accounts payable and accrued liabilities | 54,437 | |
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 | 148,048 | |
Less: fair value of assets acquired | ||
Cash | 6,971 | |
Trade accounts receivable | 13,746 | |
Other current assets | 15,664 | |
Oil and natural gas properties | 462,715 | |
Derivative assets | 90,234 | |
Other assets | 9,734 | |
Amount attributable assets acquired | 599,064 | |
Bargain Purchase Gain | $ (35,838) |
Acquisitions and Divestitures43
Acquisitions and Divestitures (Aggregate Values Assigned to Net Assets Acquired) (Details) - USD ($) $ in Thousands | Sep. 30, 2014 | Jan. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 |
Fair value of assets and liabilities acquired: | ||||
Loss on acquisition | $ (253,370) | $ (506,046) | ||
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 | |||
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) |
Acquisitions and Divestitures44
Acquisitions and Divestitures (Pro Forma) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pro Forma Information | |||
Total revenues | $ 327,066 | $ 746,770 | $ 1,430,710 |
Net income (loss) | $ (847,779) | $ (2,119,416) | $ (66,405) |
Net loss attributable to Common and Class B unitholders, per unit: | |||
Business Acquisition, Pro Forma Earnings Per Share, Basic and Diluted | $ (6.46) | $ (16.30) | $ (0.53) |
SCOOP/STACK Divestiture [Member] | |||
Pro Forma Information | |||
Total revenues | $ 17,542 | $ 57,794 | |
Business Acquisition, Pro Forma Revenue, Excess Revenue Over Expenses | $ 5,932 | $ 19,788 |
Acquisitions and Divestitures45
Acquisitions and Divestitures (Acquiree Earnings) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
LRE Merger [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | $ 46,609 | $ 13,083 | |
Excess of revenues over direct operating expenses | 25,997 | 6,029 | |
EROC Merger [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 51,307 | 23,005 | |
Excess of revenues over direct operating expenses | 27,495 | 15,112 | |
Pinedale Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 76,931 | 84,934 | $ 139,908 |
Excess of revenues over direct operating expenses | 50,183 | 56,672 | 107,934 |
Piceance Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 30,004 | 37,767 | 22,642 |
Excess of revenues over direct operating expenses | 19,612 | 18,427 | 15,234 |
Series of Individually Immaterial Business Acquisitions [Member] | |||
Business Acquisition [Line Items] | |||
Revenues | 20,989 | 36,952 | 25,989 |
Excess of revenues over direct operating expenses | $ 9,328 | $ 20,638 | $ 18,450 |
Debt (Details)
Debt (Details) | Oct. 26, 2016USD ($) | Feb. 10, 2016USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 01, 2016USD ($) | Nov. 03, 2016USD ($)payment | Oct. 03, 2016USD ($) | May 26, 2016USD ($) |
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | $ 1,773,512,000 | $ 2,282,432,000 | ||||||||
Long-term Line of Credit, Deficiency | $ 187,500,000 | |||||||||
Interest Payable | $ 15,000,000 | |||||||||
Cash paid for interest | 85,371,000 | 83,557,000 | $ 66,434,000 | |||||||
Percentage of proceeds to be paid to First Lien Lenders | 100.00% | |||||||||
Senior Notes [Abstract] | ||||||||||
Gains (Losses) on Extinguishment of Debt | $ 89,714,000 | 0 | $ 0 | |||||||
Carrying Value of Senior Notes exchanged, Net | $ 165,300,000 | |||||||||
Percentage of ownership (in hundredths) | 100.00% | |||||||||
Purchase of equipment at early buyout date | $ 16,000,000 | |||||||||
Line of Credit [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 3,500,000,000 | |||||||||
Borrowing base | $ 1,325,000,000 | $ 1,100,000,000 | $ 1,780,000,000 | |||||||
Debt amount outstanding | 1,270,000,000 | |||||||||
Long-term Line of Credit, Deficiency | (169,200,000) | $ 103,500,000 | ||||||||
Line of Credit Facility, Periodic Payment | $ 17,500,000 | |||||||||
Line of Credit, Liquidity Amount | 50,000,000 | |||||||||
Line of Credit Facility, Number of Periodic Payments | payment | 5 | |||||||||
Line of Credit [Member] | Standby Letters of Credit [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Borrowing base | $ 200,000 | |||||||||
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 | |||||||||
Senior Notes due 2020 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | 381,800,000 | 381,800,000 | ||||||||
Interest Payable | $ 15,000,000 | |||||||||
Cash paid for interest | 15,100,000 | |||||||||
Senior Notes [Abstract] | ||||||||||
Stated interest rate (in hundredths) | 7.875% | |||||||||
Senior Notes due 2019 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | $ 51,100,000 | $ 51,100,000 | ||||||||
Interest Payable | $ 2,100,000 | |||||||||
Senior Notes [Abstract] | ||||||||||
Stated interest rate (in hundredths) | 8.375% | |||||||||
Capital Lease Obligations [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | $ 20,167,000 | 24,668,000 | ||||||||
Senior Notes [Abstract] | ||||||||||
Stated interest rate (in hundredths) | 4.16% | |||||||||
May 2016 Redetermination [Member] | Line of Credit [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of Credit Facility, Periodic Payment | 29,300,000 | |||||||||
November 2016 Redetermination [Member] | Line of Credit [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of Credit Facility, Periodic Payment | $ 37,500,000 | |||||||||
Senior Notes due 2020 [Member] | Senior Notes [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | $ 381,830,000 | 550,000,000 | ||||||||
Senior Notes [Abstract] | ||||||||||
Stated interest rate (in hundredths) | 7.875% | |||||||||
Senior Notes due 2019 [Member] | Senior Notes [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt amount outstanding | $ 51,120,000 | $ 51,120,000 | ||||||||
Senior Notes [Abstract] | ||||||||||
Stated interest rate (in hundredths) | 8.375% |
Debt (Financing Arrangements) (
Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||
Unamortized Debt Issuance Expense | $ (11,072) | $ (13,705) |
Debt amount outstanding | 1,773,512 | 2,282,432 |
Long-term Debt, Current Maturities | (1,753,345) | 0 |
Short-term Debt | (4,692) | (4,501) |
Total long-term debt | 15,475 | 2,277,931 |
Line of Credit [Member] | ||
Debt Instrument [Line Items] | ||
Debt amount outstanding | 1,270,000 | |
Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized discount on Senior Notes | $ (13,167) | (17,651) |
Capital Lease Obligations [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate (in hundredths) | 4.16% | |
Maturity date | Aug. 10, 2020 | |
Debt amount outstanding | $ 20,167 | 24,668 |
Senior Secured Reserve-Based Credit Facility [Member] | Line of Credit [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate description | Variable (1) | |
Maturity date | Apr. 16, 2018 | |
Debt amount outstanding | $ 1,269,000 | $ 1,688,000 |
Variable interest rate (in hundredths) | 3.11% | 2.90% |
Senior Notes due 2023 [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate (in hundredths) | 7.00% | |
Maturity date | Feb. 15, 2023 | |
Debt amount outstanding | $ 75,634 | $ 0 |
Debt Instrument, Interest Rate, Effective Percentage | 8.00% | |
Senior Notes due 2020 [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate (in hundredths) | 7.875% | |
Maturity date | Apr. 1, 2020 | |
Debt amount outstanding | $ 381,830 | $ 550,000 |
Debt Instrument, Interest Rate, Effective Percentage | 8.00% | 8.00% |
Senior Notes due 2019 [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate (in hundredths) | 8.375% | |
Maturity date | Jun. 1, 2019 | |
Debt amount outstanding | $ 51,120 | $ 51,120 |
Debt Instrument, Interest Rate, Effective Percentage | 21.45% | 21.45% |
Price and Interest rate Risk 48
Price and Interest rate Risk Management Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | ||
Fair value of derivative contracts terminated | $ 53,955 | $ 69,515 |
Price and Interest Rate Risk 49
Price and Interest Rate Risk Management Activities (Interest Rate Swaps) (Details) - Contract period - January 1, 2017 to February 16, 2017 [Member] - Interest rate swaps [Member] $ in Thousands | Dec. 31, 2016USD ($) |
Derivative [Line Items] | |
Notional amount | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.725% |
Price and Interest Rate Risk 50
Price and Interest Rate Risk Management Activities (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 349,281 | |
Derivative Asset, Fair Value, Gross Liability | (32,234) | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 317,047 | |
Derivative Liability, Fair Value, Gross Liability | (32,590) | |
Derivative Liability, Fair Value, Gross Asset | 32,234 | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ (125) | (356) |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 349,281 | |
Derivative Asset, Fair Value, Gross Liability | (21,834) | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 327,447 | |
Derivative Liability, Fair Value, Gross Liability | (21,934) | |
Derivative Liability, Fair Value, Gross Asset | 21,834 | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (100) | |
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) | |
Derivative Liability, Fair Value, Gross Asset | 10,400 | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ (125) | $ (256) |
Price and Interest Rate Risk 51
Price and Interest Rate Risk Management Activities (Change in Fair Value of Derivatives) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | |||
Derivative asset/(liability) at beginning of year, net | $ 316,691 | $ 220,734 | $ 66,711 |
Fair value of derivative contracts acquired through business combinations | 0 | 195,273 | (1,344) |
Premiums and fees paid or deferred for derivative contracts during the period | (2,444) | 7,126 | 0 |
Net (gains) losses on commodity and interest rate derivative contracts | (46,939) | 169,569 | 161,519 |
Cash settlements received on matured commodity derivative contracts | (226,876) | (211,723) | (10,187) |
Cash settlements paid on matured interest rate derivative contracts | 13,398 | 5,227 | 4,035 |
Fair value of derivative contracts terminated | (53,955) | (69,515) | |
Derivative asset/(liability) at end of year, net | $ (125) | $ 316,691 | $ 220,734 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment of goodwill | $ 252,676 | $ 71,425 | $ 0 |
Goodwill | 253,370 | 506,046 | |
Asset retirement obligations incurred and assumed from business combinations | 700 | 90,900 | |
Change in estimate | $ 1,267 | 22,329 | |
Average inflation rate (in hundredths) | 2.00% | ||
Minimum [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Credit-adjusted risk-free interest rate (in hundredths) | 4.60% | ||
Maximum [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
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 | ||
Interest rate derivative contracts | (10,400) | ||
Total derivative instruments | 317,047 | ||
Liabilities: | |||
Commodity price derivative contracts | (99) | ||
Interest rate derivative contract | $ (125) | (257) | |
Total derivative instruments | (125) | (356) | |
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 1 [Member] | |||
Assets: | |||
Commodity price derivative contracts | 0 | ||
Interest rate derivative contracts | 0 | ||
Total derivative instruments | 0 | ||
Liabilities: | |||
Commodity price derivative contracts | 0 | ||
Interest rate derivative contract | 0 | ||
Total derivative instruments | 0 | ||
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 2 [Member] | |||
Assets: | |||
Commodity price derivative contracts | 333,380 | ||
Interest rate derivative contracts | (10,400) | ||
Total derivative instruments | 322,980 | ||
Liabilities: | |||
Commodity price derivative contracts | (99) | ||
Interest rate derivative contract | (125) | (257) | |
Total derivative instruments | (125) | (356) | |
Fair Value Measured on a Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Assets: | |||
Commodity price derivative contracts | (5,933) | ||
Interest rate derivative contracts | 0 | ||
Total derivative instruments | (5,933) | ||
Liabilities: | |||
Commodity price derivative contracts | 0 | ||
Interest rate derivative contract | 0 | ||
Total derivative instruments | $ 0 | ||
Senior Notes due 2020 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt Instrument, Fair Value Disclosure | 225,300 | ||
Senior Notes due 2019 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt Instrument, Fair Value Disclosure | 26,600 | ||
Senior Notes due 2023 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Debt Instrument, Fair Value Disclosure | $ 56,900 |
Fair Value Measurements - Unobs
Fair Value Measurements - Unobservable Inputs Reconciliation (Details) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Asset retirement obligations | $ 8,935 | $ 24,766 | $ 56,947 |
Liabilities added during the current period | 713 | 2,699 | |
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 | (5,933) | (6,470) | |
Total gains | 11,838 | 5,151 | |
Settlements | (5,905) | (4,614) | |
Unobservable inputs at end of year | 0 | (5,933) | $ (6,470) |
Change in fair value included in earnings related to derivatives still held as of end of year | $ 0 | $ (2,925) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Changes in asset retirement obligations [Abstract] | |||
Asset retirement obligation at January 1, | $ 271,456 | $ 149,062 | |
Liabilities added during the current period | 713 | 2,699 | |
Liabilities added from the LRE and Eagle Rock Mergers | 0 | 88,228 | |
Accretion expense | 12,145 | 10,238 | $ 5,900 |
Change in estimate | 1,267 | 22,329 | |
Disposition of properties | (10,915) | (262) | |
Retirements | (2,230) | (838) | |
Total asset retirement obligation at December 31, | 272,436 | 271,456 | $ 149,062 |
Less: current obligations | (7,884) | (9,024) | |
Long-term asset retirement obligation at December 31, | $ 264,552 | $ 262,432 |
Commitments and Contingencies55
Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Gross future minimum transportation demand | |
2,017 | $ 12,538 |
2,018 | 11,678 |
2,019 | 9,661 |
2,020 | 410 |
Total | $ 34,287 |
Minimum [Member] | |
Oil and Gas Delivery Commitments and Contracts | |
Remaining term of contracts | 1 month |
Maximum [Member] | |
Oil and Gas Delivery Commitments and Contracts | |
Remaining term of contracts | 4 years |
Commitments and Contingencies -
Commitments and Contingencies - Development Commitment (Details) $ in Millions | Dec. 31, 2016USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Development Commitment, Remaining Minimum Amount Committed | $ 13.7 |
Members' Equity (Deficit) and57
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, 2016 | Dec. 31, 2015 | |
Preferred stock, liquidation preference (in dollars 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 (in dollars per share) | $ 25 | |
Preferred unit, distribution rate (as a percent) | 7.875% | |
Preferred units, outstanding | 2,581,873 | 2,581,873 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 62,200 | $ 62,200 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 4,200 | |
Series B Preferred Units [Member] | ||
Preferred stock, liquidation preference (in dollars per share) | $ 25 | |
Preferred unit, distribution rate (as a percent) | 7.625% | |
Preferred units, outstanding | 7,000,000 | 7,000,000 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 169,265 | $ 169,265 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 11,100 | |
Series C Preferred Units [Member] | ||
Preferred stock, liquidation preference (in dollars per share) | $ 25 | |
Preferred unit, distribution rate (as a percent) | 7.75% | |
Preferred units, outstanding | 4,300,000 | 4,300,000 |
Limited Liability Company (LLC) Preferred Unit, Issuance Value | $ 103,979 | $ 103,979 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 6,900 |
Members' Equity (Deficit) and58
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Oct. 15, 2014 | |
Class of Stock [Line Items] | ||||
Stock Repurchase Program, Authorized Amount | $ 10,000,000 | |||
Stock Repurchased During Period, Shares | 291,926 | |||
Treasury Stock, Carrying Basis | $ 4,900,000 | |||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Treasury Stock, Shares, Acquired | 0 | (157,000) | (135,000) | |
Common Units [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units | 130,477,000 | 83,452,000 | 78,337,000 | |
Partners' Capital Account, Units, Sale of Units | 0 | 2,430,000 | 4,864,000 | |
Partners' Capital Account, Units, Unit-based Compensation | 532,000 | 1,418,000 | 386,000 | |
Partners' Capital Account, Units | 131,009,000 | 130,477,000 | 83,452,000 | |
EROC Merger [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units, Acquisitions | 0 | 27,886,000 | 0 | |
LRE Merger [Member] | ||||
Increase (Decrease) in Common Units [Roll Forward] | ||||
Partners' Capital Account, Units, Acquisitions | 0 | 15,448,000 | 0 |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Antidilutive securities | |||
Net income (loss) attributable to Common and Class B unitholders | $ (841,847) | $ (1,909,933) | $ 46,148 |
Weighted average units outstanding - basic (in shares) | 131,323,000 | 96,468,000 | 82,031,000 |
Weighted average units outstanding - diluted (in shares) | 131,323,000 | 96,468,000 | 82,459,000 |
Earnings Per Share, Basic (in dollars per share) | $ (6.41) | $ (19.80) | $ 0.56 |
Earnings Per Share, Diluted (in dollars per share) | $ (6.41) | $ (19.80) | $ 0.55 |
Phantom Share Units (PSUs) [Member] | |||
Antidilutive securities | |||
Antidilutive securities (in shares) | 3,799,304 | 164,984 | |
Phantom Share Units (PSUs) [Member] | |||
Antidilutive securities | |||
Effect of dilutive securities, Phantom units (in shares) | 0 | 0 | 428,000 |
Members' Equity (Deficit) and60
Members' Equity (Deficit) and Net Income (Loss) per Common and Class B Unit - Distributions Declared (Details) - $ / shares | 1 Months Ended | 12 Months Ended | |||||||||||||||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Jan. 31, 2016 | Dec. 31, 2015 | 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 | Aug. 31, 2014 | Jul. 31, 2014 | May 31, 2014 | Apr. 30, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2016 | |
Preferred stock, liquidation preference (in dollars per share) | $ 25 | $ 25 | |||||||||||||||||||||||||
Series A Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred unit, distribution rate (as a percent) | 7.875% | ||||||||||||||||||||||||||
Preferred stock, liquidation preference (in dollars per share) | 25 | $ 25 | |||||||||||||||||||||||||
Series B Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred unit, distribution rate (as a percent) | 7.625% | ||||||||||||||||||||||||||
Preferred stock, liquidation preference (in dollars per share) | 25 | $ 25 | |||||||||||||||||||||||||
Series C Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred unit, distribution rate (as a percent) | 7.75% | ||||||||||||||||||||||||||
Preferred stock, liquidation preference (in dollars per share) | 25 | $ 25 | |||||||||||||||||||||||||
Common Units [Member] | |||||||||||||||||||||||||||
Distributions Declared [Abstract] | |||||||||||||||||||||||||||
Cash Distributions Per Unit (in dollars per share) | $ 0.03 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.03 | $ 0.21 | $ 0.03 | $ 0.1175 | $ 0.21 | $ 0.1175 | $ 0.1175 | $ 0.21 | $ 0.1175 | $ 0.1175 | $ 0.21 | $ 0.1175 | $ 0.1175 | $ 0.2075 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.21 | $ 0.2075 | |
Cash Distributions Declared Date | Jan. 20, 2016 | Oct. 19, 2015 | Jul. 16, 2015 | Apr. 15, 2015 | Feb. 18, 2016 | Jan. 22, 2015 | Dec. 18, 2015 | Nov. 20, 2015 | Oct. 20, 2014 | Sep. 21, 2015 | Aug. 20, 2015 | Jul. 16, 2014 | Jun. 18, 2015 | May 19, 2015 | Apr. 17, 2014 | Mar. 18, 2015 | Feb. 17, 2015 | Jan. 16, 2014 | Dec. 16, 2014 | Nov. 20, 2014 | Sep. 19, 2014 | Aug. 19, 2014 | Jun. 24, 2014 | May 20, 2014 | Mar. 17, 2014 | Feb. 2, 2014 | |
Cash Distributions Record Date | Feb. 1, 2016 | Nov. 2, 2015 | Aug. 3, 2015 | May 1, 2015 | Mar. 1, 2016 | Feb. 2, 2015 | Jan. 4, 2016 | Dec. 1, 2015 | Nov. 3, 2014 | Oct. 1, 2015 | Sep. 1, 2015 | Aug. 1, 2014 | Jul. 1, 2015 | Jun. 1, 2015 | May 1, 2014 | Apr. 1, 2015 | Mar. 2, 2015 | Feb. 3, 2014 | Jan. 2, 2015 | Dec. 1, 2014 | Oct. 1, 2014 | Sep. 2, 2014 | Jul. 1, 2014 | Jun. 2, 2014 | Apr. 1, 2014 | Mar. 3, 2014 | |
Cash Distributions Payment Date | Feb. 12, 2016 | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Mar. 15, 2016 | Feb. 13, 2015 | Jan. 14, 2016 | Dec. 15, 2015 | Nov. 14, 2014 | Oct. 15, 2015 | Sep. 14, 2015 | Aug. 14, 2014 | Jul. 15, 2015 | Jun. 12, 2015 | May 15, 2014 | Apr. 14, 2015 | Mar. 17, 2015 | Feb. 14, 2014 | Jan. 14, 2015 | Dec. 15, 2014 | Oct. 15, 2014 | Sep. 12, 2014 | Jul. 15, 2014 | Jun. 13, 2014 | Apr. 14, 2014 | Mar. 17, 2014 |
Unit-Based Compensation (Detail
Unit-Based Compensation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)officershares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Accrued liability | $ 0.4 | $ 1.1 | |
Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation cost | $ 4.3 | ||
Unrecognized compensation cost recognition period (in years) | 1 year | ||
Phantom Share Units (PSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation cost | $ 6.7 | ||
Unrecognized compensation cost recognition period (in years) | 1 year | ||
Phantom Share Units (PSUs) [Member] | Board Member [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 1 year | ||
Units granted (in units) | shares | 125,838 | ||
VNR LTIP [Member] | Restricted Stock Units (RSUs) [Member] | Employee [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units granted (in units) | shares | 7,500 | ||
VNR LTIP [Member] | Phantom Share Units (PSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Units granted (in units) | shares | 1,331,579 | ||
Amended Agreements [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of executives in amended agreements | officer | 3 | ||
Amended Agreements [Member] | Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Ratio of aggregate restricted units that will vest on each one-year anniversary | 33.33% | ||
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% | ||
Amended Agreements [Member] | Phantom Share Units (PSUs) [Member] | Executive Officer [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units granted (in units) | shares | 2,255,033 | ||
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 | $ 5.4 | 16.9 | $ 10.7 |
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 | 4.8 | 1.7 | 1 |
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 | $ 1.8 | $ 1.1 | $ 1.4 |
Unit-Based Compensation - Summa
Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - Restricted Stock Units (RSUs) [Member] - VNR LTIP [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Number of Non-vested Units | |||
Non-vested units, beginning of year (in units) | 976,348 | ||
Granted (in units) | 7,500 | ||
Forfeited (in units) | (60,971) | ||
Vested (in units) | (275,093) | ||
Non-vested units, end of year (in units) | 647,784 | 976,348 | |
Weighted Average Grant Date Fair Value | |||
Non-vested units at beginning of year (in dollars per unit) | $ 18.29 | ||
Granted (in dollars per unit) | 3.11 | $ 15.17 | $ 29.02 |
Forfeited (in dollars per unit) | 14.36 | ||
Vested (in dollars per unit) | 17 | ||
Non-vested units at end of year (in dollars per unit) | $ 19.14 | $ 18.29 |
Unit-Based Compensation - Sum63
Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - Phantom Share Units (PSUs) [Member] - VNR Long Term Incentive Plan [Member] | 12 Months Ended |
Dec. 31, 2016$ / sharesshares | |
Number of Non-vested Units | |
Non-vested units, beginning of year (in units) | shares | 203,221 |
Granted (in units) | shares | 3,712,450 |
Forfeited (in units) | shares | (164,507) |
Vested (in units) | shares | (122,635) |
Non-vested units, end of year (in units) | shares | 3,628,529 |
Weighted Average Grant Date Fair Value | |
Non-vested units at beginning of year (in dollars per unit) | $ / shares | $ 20.99 |
Granted (in dollars per unit) | $ / shares | 2.56 |
Forfeited (in dollars per unit) | $ / shares | 1.85 |
Vested (in dollars per unit) | $ / shares | 22.23 |
Non-vested units at end of year (in dollars per unit) | $ / shares | $ 2.96 |
Shelf Registration Statements (
Shelf Registration Statements (Details) | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Common Units [Member] | |
Shelf Registration Statements [Line Items] | |
Maximum offering under equity distribution agreement | $ 14,593,606 |