Document and Entity Information
Document and Entity Information - $ / shares | 6 Months Ended | |
Jun. 30, 2017 | Aug. 01, 2017 | |
Document Information [Line Items] | ||
Entity Registrant Name | Vanguard Natural Resources, Inc. | |
Entity Central Index Key | 1,384,072 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 20,055,694 | |
Subsequent Event [Member] | ||
Document Information [Line Items] | ||
Common Stock, Par or Stated Value Per Share | $ 0.001 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Revenues: | ||||
Oil sales | $ 41,046 | $ 49,941 | $ 85,676 | $ 85,595 |
Natural gas sales | 51,712 | 32,431 | 109,175 | 69,302 |
NGLs sales | 14,109 | 11,104 | 30,773 | 20,019 |
Net losses on commodity derivative contracts | (12,875) | (68,610) | (12,868) | (36,851) |
Total revenues | 93,992 | 24,866 | 212,756 | 138,065 |
Production: | ||||
Lease operating expenses | 36,823 | 38,515 | 75,305 | 80,842 |
Production and other taxes | 9,138 | 9,476 | 19,203 | 18,144 |
Depreciation, depletion, amortization, and accretion | 25,328 | 38,786 | 51,056 | 86,839 |
Impairment of oil and natural gas properties | 0 | 157,894 | 0 | 365,658 |
Selling, general and administrative expenses | 9,777 | 13,408 | 20,072 | 24,430 |
Total costs and expenses | 81,066 | 258,079 | 165,636 | 575,913 |
Income (loss) from operations | 12,926 | (233,213) | 47,120 | (437,848) |
Other income (expense): | ||||
Interest expense (excludes contractual interest expense of $8.6 million and $14.3 million for the three and six months ended June 30, 2017, respectively) | (13,832) | (23,932) | (30,273) | (49,636) |
Net gains (losses) on interest rate derivative contracts | 0 | (2,135) | 30 | (6,825) |
Net loss on acquisition of oil and natural gas properties | 0 | (1,665) | 0 | (1,665) |
Gain on extinguishment of debt | 0 | 0 | 0 | 89,714 |
Other | 255 | 196 | 311 | 252 |
Total other income (expense), net | (13,577) | (27,536) | (29,932) | 31,840 |
Income (loss) before reorganization items | (651) | (260,749) | 17,188 | (406,008) |
Reorganization items (Note 2) | (53,221) | 0 | (79,967) | 0 |
Net loss | (53,872) | (260,749) | (62,779) | (406,008) |
Less: Net income (loss) attributable to non-controlling interests | 5 | (40) | (12) | (64) |
Net loss attributable to Vanguard unitholders | (53,867) | (260,789) | (62,791) | (406,072) |
Distributions to Preferred unitholders | 0 | (6,689) | (2,230) | (13,379) |
Net loss attributable to Common and Class B unitholders | $ (53,867) | $ (267,478) | $ (65,021) | $ (419,451) |
Net loss per Common and Class B unit – basic and diluted (in usd per share) | $ (0.41) | $ (2.04) | $ (0.49) | $ (3.20) |
Common Units | ||||
Other income (expense): | ||||
Weighted average Common units outstanding – basic & diluted (in shares) | 130,961 | 131,015 | 130,959 | 130,772 |
Class B Units | ||||
Other income (expense): | ||||
Weighted average Common units outstanding – basic & diluted (in shares) | 420 | 420 | 420 | 420 |
CONSOLIDATED STATEMENTS OF OPE3
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2017 | Jun. 30, 2017 | |
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | $ 8.6 | $ 14.3 |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 168,255 | $ 49,957 |
Trade accounts receivable, net | 84,294 | 97,138 |
Other current assets | 3,768 | 7,944 |
Total current assets | 256,317 | 155,039 |
Oil and natural gas properties, at cost | 4,647,438 | 4,725,692 |
Accumulated depletion, amortization and impairment | (3,910,989) | (3,867,439) |
Oil and natural gas properties evaluated, net – full cost method | 736,449 | 858,253 |
Other assets | ||
Goodwill | 253,370 | 253,370 |
Other assets | 44,424 | 42,626 |
Total assets | 1,290,560 | 1,309,288 |
Accounts payable: | ||
Trade | 3,841 | 12,929 |
Affiliates | 0 | 1,443 |
Accrued liabilities: | ||
Lease operating | 13,505 | 14,909 |
Developmental capital | 8,574 | 6,676 |
Interest | 7,650 | 13,345 |
Production and other taxes | 34,754 | 32,663 |
Other | 17,421 | 5,416 |
Derivative liabilities | 4,694 | 125 |
Oil and natural gas revenue payable | 26,145 | 33,672 |
Long-term debt classified as current | 1,319,157 | 1,753,345 |
Other current liabilities | 14,382 | 14,160 |
Total current liabilities | 1,450,123 | 1,888,683 |
Long-term debt, net of current portion (Note 4) | 13,055 | 15,475 |
Derivative liabilities | 8,181 | 0 |
Asset retirement obligations, net of current portion | 261,013 | 264,552 |
Other long-term liabilities | 39,050 | 39,443 |
Total liabilities not subject to compromise | 1,771,422 | 2,208,153 |
Liabilities subject to compromise (Note 2) | 476,268 | 0 |
Total liabilities | 2,247,690 | 2,208,153 |
Commitments and contingencies (Note 8) | ||
Members’ deficit (Note 9) | ||
Partners' Capital | (957,130) | (898,865) |
Total VNR members’ deficit | (963,750) | (905,708) |
Non-controlling interest in subsidiary | 6,620 | 6,843 |
Total members’ deficit | (957,130) | (898,865) |
Total liabilities and members’ deficit | 1,290,560 | 1,309,288 |
Member Units | Cumulative Preferred Units | ||
Members’ deficit (Note 9) | ||
Partners' Capital | 335,444 | 335,444 |
Member Units | Common Units | ||
Members’ deficit (Note 9) | ||
Partners' Capital | (1,306,809) | (1,248,767) |
Member Units | Class B Units | ||
Members’ deficit (Note 9) | ||
Partners' Capital | $ 7,615 | $ 7,615 |
CONSOLIDATED BALANCE SHEETS (U5
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares | Jun. 30, 2017 | Dec. 31, 2016 |
Members’ deficit (Note 9) | ||
Preferred units, issued (shares) | 13,881,873 | 13,881,873 |
Preferred units, outstanding (shares) | 13,881,873 | 13,881,873 |
Common Units | ||
Members’ deficit (Note 9) | ||
Common units, issued (shares) | 130,978,907 | 131,008,670 |
Common units, outstanding (shares) | 130,978,907 | 131,008,670 |
Class B Units | ||
Members’ deficit (Note 9) | ||
Common units, issued (shares) | 420,000 | 420,000 |
Common units, outstanding (shares) | 420,000 | 420,000 |
CONSOLIDATED STATEMENTS OF MEMB
CONSOLIDATED STATEMENTS OF MEMBERS' DEFICIT (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Balance | $ (898,865) | $ (87,435) | $ (87,435) | |
Distributions to Preferred unitholders (see Note 9) | (5,575) | |||
Distributions to Common and Class B unitholders (see Note 9) | (7,998) | |||
Unit-based compensation | 4,765 | 10,639 | ||
Net income (loss) | $ (53,872) | (62,779) | (406,008) | (815,007) |
Non-controlling interest in subsidiary | 7,452 | |||
Potato Hills cash distribution to non-controlling interest | (235) | (691) | ||
Balance | (957,130) | (957,130) | (898,865) | |
Non-controlling Interest | ||||
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Balance | 6,843 | 0 | 0 | |
Net income (loss) | 12 | 82 | ||
Non-controlling interest in subsidiary | 7,452 | |||
Potato Hills cash distribution to non-controlling interest | (235) | (691) | ||
Balance | 6,620 | 6,620 | 6,843 | |
Cumulative Preferred Units | Member Units | ||||
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Balance | 335,444 | 335,444 | 335,444 | |
Distributions to Preferred unitholders (see Note 9) | (5,575) | |||
Balance | 335,444 | 335,444 | 335,444 | |
Common Units | ||||
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Issuance costs related to prior period equity transactions | (16) | (250) | ||
Common Units | Member Units | ||||
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Balance | (1,248,767) | (430,494) | (430,494) | |
Issuance costs related to prior period equity transactions | (16) | (250) | ||
Distributions to Common and Class B unitholders (see Note 9) | (7,998) | |||
Unit-based compensation | 4,765 | 10,639 | ||
Net income (loss) | (62,791) | (815,089) | ||
Balance | (1,306,809) | (1,306,809) | (1,248,767) | |
Class B Units | Member Units | ||||
Increase (Decrease) in Members' Equity [Roll Forward] | ||||
Balance | 7,615 | $ 7,615 | 7,615 | |
Balance | $ 7,615 | $ 7,615 | $ 7,615 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Operating activities | ||
Net loss | $ (62,779) | $ (406,008) |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion, amortization, and accretion | 51,056 | 86,839 |
Impairment of oil and natural gas properties | 0 | 365,658 |
Amortization of deferred financing costs | 2,228 | 2,348 |
Amortization of debt discount | 348 | 1,783 |
Non-cash reorganization items | 58,755 | 0 |
Compensation related items | 4,765 | 6,103 |
Net losses on commodity and interest rate derivative contracts | 12,838 | 43,676 |
Cash settlements received on matured commodity derivative contracts | 7 | 142,476 |
Cash settlements paid on matured interest rate derivative contracts | (95) | (4,727) |
Net loss on acquisition of oil and natural gas properties | 0 | (1,665) |
Gain on extinguishment of debt | 0 | (89,714) |
Changes in operating assets and liabilities: | ||
Trade accounts receivable | 14,804 | 25,427 |
Other current assets | 2,106 | (96) |
Net premiums received (paid) on commodity derivative contracts | (16) | 905 |
Accounts payable and oil and natural gas revenue payable | (14,484) | (40,220) |
Payable to affiliates | (890) | (277) |
Accrued expenses and other current liabilities | 5,564 | (41,323) |
Other assets | (357) | (2,965) |
Net cash provided by operating activities | 73,850 | 91,550 |
Investing activities | ||
Additions to property and equipment | (67) | (36) |
Potato Hills Gas Gathering System acquisition | 0 | (7,470) |
Additions to oil and natural gas properties | (17,873) | (28,009) |
Deposits and prepayments of oil and natural gas properties | (22,330) | (5,342) |
Proceeds from the sale of oil and natural gas properties | 107,689 | 285,590 |
Net cash provided by investing activities | 67,419 | 244,733 |
Financing activities | ||
Proceeds from long-term debt | 0 | 93,500 |
Repayment of long-term debt | (22,683) | (377,228) |
Distributions to Preferred unitholders | 0 | (6,690) |
Distributions to Common and Class B unitholders | 0 | (11,917) |
Potato Hills distribution to non-controlling interest | (235) | (230) |
Financing fees | (53) | (2,543) |
Net cash used in financing activities | (22,971) | (305,108) |
Net increase cash and cash equivalents | 118,298 | 31,175 |
Cash and cash equivalents, beginning of period | 49,957 | 0 |
Cash and cash equivalents, end of period | 168,255 | 31,175 |
Supplemental cash flow information: | ||
Cash paid for interest | 22,424 | 47,008 |
Non-cash investing activity: | ||
Asset retirement obligations, net | $ 7,890 | $ 10,045 |
Description of the Business
Description of the Business | 6 Months Ended |
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Description of Business | Description of the Business We are an independent oil and gas company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Through our operating subsidiaries, as of June 30, 2017 , we own properties and oil and natural gas reserves primarily located in ten operating areas: • the Green River Basin in Wyoming; • the Piceance Basin in Colorado; • the Permian Basin in West Texas and New Mexico; • 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 Anadarko Basin in Oklahoma and North Texas; • the Williston Basin in North Dakota and Montana; • the Wind River Basin in Wyoming; and • the Powder River Basin in Wyoming. We were formed in October 2006 and completed our initial public offering in October 2007. Following the completion of the financial restructuring, the Company will have 20.1 million shares of its common stock outstanding. We expect that the Company’s shares of common stock and warrants will be traded and quoted on the OTCQX market (which is operated by OTC Markets Group, Inc.). The OTCQX market is an interdealer quotation system providing real time quotation services, each of which the Company believes constitutes an “established securities market” within the meaning of the Foreign Investment in Real Property Tax Act of 1980. The Company expects the new listing to go effective during the third quarter of 2017. Additionally, the Company is moving forward as a corporation for U.S. federal income tax purposes. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2016 from the audited financial statements contained in our 2016 Annual Report. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2016 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. As of June 30, 2017 , our significant accounting policies, except for those related to the effects of our Chapter 11 Cases discussed below, are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2016 Annual Report. (a) Basis of Presentation and Principles of Consolidation The consolidated financial statements as of June 30, 2017 and December 31, 2016 and for the three and six months ended June 30, 2017 and 2016 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. 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 Cases On February 1, 2017 (the “Petition 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. Please read Note 2. Chapter 11 Cases for a discussion of the Chapter 11 Cases (as defined in Note 2). For periods subsequent to filing the Bankruptcy Petitions (as defined in Note 2), we have prepared our consolidated financial statements in accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. (c) 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 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 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 future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, 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 six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. No ceiling test impairment was required during the six months ended June 30, 2017 . When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. (d) Goodwill and Other Intangible Assets We account for goodwill 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. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) (ASU 2017-04) to simplify the accounting for goodwill impairment. The guidance eliminated the need for Step 2 of the goodwill impairment test, which required 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 eliminated the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. We elected to early adopt ASU 2017-04 for the quarter ended March 31, 2017. We did not record any goodwill impairment during the six months ended June 30, 2017 since the carrying value of our reporting unit was negative at June 30, 2017 . (e) 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, other than additional disclosures, 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, 2016, 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 add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU No. 2017-01). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. This ASU will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and should be applied prospectively. The Company is currently evaluating the provisions of ASU 2017-01 and assessing the impact adoption may have on our consolidated financial statements. Currently, we do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements, however these amendments could result in the recording of fewer business combinations in future periods. (f) 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 and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and 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. (g) 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 Quarterly Report on Form 10-Q. |
Chapter 11 Cases
Chapter 11 Cases | 6 Months Ended |
Jun. 30, 2017 | |
Chapter 11 Cases [Abstract] | |
Chapter 11 Proceedings | Chapter 11 Cases Commencement of Chapter 11 Cases On February 1, 2017 , the Predecessor and certain subsidiaries (such subsidiaries, together with the Predecessor, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy 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 Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.” The subsidiary Debtors in the Chapter 11 Cases were the Successor; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUD II; ERAP; ERAP II; EAC; and EOC. Reorganization Process We operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. To assure ordinary course operations during the pendency of the Chapter 11 Cases, the Bankruptcy Court granted certain relief requested by the Debtors, including, among other things and subject to the terms and conditions of such orders, authorizing us to maintain our existing cash management system, to secure debtor-in-possession financing, to remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and to pay the prepetition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. This relief is designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. For goods and services provided following the Petition Date, we paid vendors in full under normal terms. Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the Petition Date were automatically enjoined. This prohibited, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, all of our prepetition liabilities and obligations were settled or compromised under the Bankruptcy Code through our Chapter 11 Cases. Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2016 Annual Report. These include risks and uncertainties arising as a result of our Chapter 11 Cases, and the number and nature of our outstanding Common Stock (as defined below) and shareholders, assets, liabilities, officers and directors could change materially because of our Chapter 11 cases. In addition, the descriptions of our prepetition operations, properties and capital plans included in this Quarterly Report on Form 10-Q may not accurately reflect our post-emergence operations, properties and capital plans. Creditors’ Committees — Appointment & Formation (a) Restructuring Support Parties Prior to the filing of the Bankruptcy Petitions, on February 1, 2017 , we entered into a restructuring support agreement (the “Initial RSA”). The Debtors entered into the Initial RSA with (i) certain holders (the “Consenting 2020 Noteholders”) constituting at the time of signing 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 at the time of signing 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, Consenting Senior Noteholders), constituting at the time of signing approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Old Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”). On June 6, 2017, certain lenders under the Company’s Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”), among them Citibank, N.A., as administrative agent (such lenders, the “Consenting RBL Lenders” and, together with the Consenting Senior Noteholders and Consenting Second Lien Noteholders, the “Restructuring Support Parties”), became parties to the amended Restructuring Support Agreement dated as of May 23, 2017 (the “Amended RSA”). (b) Official Unsecured Creditors Committee On February 14, 2017, the Office of the United States Trustee appointed the Official Committee of Unsecured Creditors (the “Unsecured Creditors Committee”) pursuant to section 1102 of the Bankruptcy Code. The Unsecured Creditors Committee consists of the following three members: (i) UMB Bank, National Association, as Indenture Trustee; (ii) Wilmington Trust, National Association, as Indenture Trustee; and (iii) Encana Oil & Gas (USA), Inc. (c) Ad Hoc Equity Committee On March 16, 2017, we filed a motion with the Bankruptcy Court disclosing a Stipulation and Agreed Order entered into on March 15, 2017, by and between the Debtors and certain unaffiliated holders of our Preferred Units and common units (the “Ad Hoc Equity Committee”) pursuant to which the Debtors and the Ad Hoc Equity Committee agreed, among other things, that professionals for the Ad Hoc Equity Committee would be funded by the Debtors’ estates for services performed within a defined scope and subject to agreed caps on fees and expenses as described in the Stipulation and Agreed Order. Magnitude of Potential Claims On March 16, 2017, the Debtors filed with the Bankruptcy Court Schedules and Statements, as defined below, setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The Schedules and Statements may be subject to further amendment or modification after filing. Certain holders of prepetition claims were required to file proofs of claim by their respective specified deadlines for filing certain proofs of claims in the Debtors’ Chapter 11 cases. Differences between amounts scheduled by the Debtors and claims by creditors have been and are being investigated and resolved through the claims resolution process. The claims resolution process continues after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated. Schedules and Statements — Claims & Claims Resolution Process To the best of our knowledge, we notified all of our known current or potential creditors that the Debtors filed Chapter 11 cases. On March 16, 2017, each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors was a party, were subject to the qualifications and assumptions included therein, and were subject to amendment or modification over the course of the Chapter 11 Cases. Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. In addition, there were variances between the amounts for certain claims listed in the Schedules and Statements and the amounts claimed by our creditors. Such variances, as well as other disputes and contingencies will be investigated and resolved through the claims resolution process in our Chapter 11 Cases. Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wished to assert prepetition claims against us and whose claim (i) was not listed in the Schedules and Statements or (ii) was listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to April 30, 2017 for non-governmental creditors and July 31, 2017 for governmental creditors As of July 31, 2017, approximately 1,040 claims totaling $19.5 billion have been filed with the Bankruptcy Court against the Debtors by approximately 800 claimants. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We expect the process of resolving claims filed against the Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with our Plan. As part of the process, we will work to resolve differences in amounts scheduled by the Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where necessary. Through the claims resolution process as set forth in the Plan, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have filed and will file objections with the Bankruptcy Court as necessary for the claims we believe should be disallowed. Claims that have been allowed or we believe are allowable are reflected in “Liabilities Subject to Compromise.” As discussed above, the claims resolution process continues following our emergence from the Chapter 11 Cases. Accordingly, the ultimate number and amount of claims that will be allowed against the Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated. Restructuring Support Agreement The Initial RSA and Amended RSA set 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”) to be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases. A summary of the restructuring transactions agreed to by the Restructuring Support Parties and to be effectuated through the Plan is included below. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Initial RSA and Amended RSA. Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code The Initial RSA contemplated the following Restructuring Transactions outlined below: • Allowed claims (“First Lien Claims”) under the Reserve-Based Credit Facility to be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and to be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims to 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 the same lenders under the Reserve-Based Credit Facility. • Allowed Second Lien Claims to receive new notes in the current principal amount of approximately $75.6 million , 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 to 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 was accepted by the classes of the general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units to receive their pro rata share of (a) 3% of the New Equity Interests and (b) three and a half year warrants for 3% of the New Equity Interests. • A $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 to execute a backstop commitment agreement to fully backstop the Senior Note Rights Offering. • The Second Lien Investors to purchase $19.3 million in New Equity Interests at a 25% discount to the Company’s total enterprise value. The initial terms also provided for the establishment of a management incentive plan at the Company under which 10% of the New Equity Interests would have been reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities. The initial RSA obligated 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. Second Amended Joint Plan of Reorganization The following is a summary of the material terms of the Second Amended Joint Plan of Reorganization which was filed on May 31, 2017 and agreed to by the Restructuring Support Parties to the Amended RSA. This summary highlights only certain substantive provisions of this iteration of the Plan and is not intended to be a complete description of that iteration of the Plan. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Second Amended Joint Plan of Reorganization. The Second Amended Joint Plan of Reorganization provided for: • The Rights Offering, consisting of (i) a $10.2 million rights offering to be conducted in reliance upon the exemption from registration under the Securities Act provided in section 1145 of the Bankruptcy Code, pursuant to which Holders of Senior Notes Claims are entitled to purchase equity in Reorganized VNR Finance, (ii) a $117.7 million rights offering to be conducted in reliance upon the exemption from registration under the Securities Act provided in section 4(a)(2) of the Securities Act, pursuant to which Accredited Investor Eligible Holders of Senior Notes Claims are entitled to purchase equity in Reorganized VNR Finance, and (iii) a $127.9 million equity investment, pursuant to which the Commitment Parties will purchase equity in Reorganized VNR Finance. The Rights Offering Shares equal 84.8% of the New Common Stock, subject to dilution by the GUC Rights Offering, the New Management Incentive Plan, the New Common Stock issuable upon exercise of the New Warrants, and the New Common Stock issued to Encana; • A fully committed $19.3 million equity investment from the Second Lien Investors for shares of New Common Stock equal to 6.4% of the aggregate New Common Stock as of the Effective Date and subject to dilution as set forth in the Plan; • A full recovery for Holders of Allowed Lender Claims consisting of (i) cash in the amount of the Credit Agreement Interest plus (ii) cash in the amount of its Pro Rata share of the Glasscock Sale Proceeds. In addition, each such Holder shall receive treatment under either Option 1 or Option 2 below. If the Holder elects (or is deemed to elect, upon its execution of the Exit Facility Credit Agreement) Option 1 on its Ballot, it shall also receive its Option 1 Pro Rata Share of (i) the Lender Paydown, (ii) the Exit Revolving Loans, and (iii) the Exit Term A Loans. If such Holder elects Option 2 on its Ballot, it shall also receive its Option 2 Pro Rata Share of the Exit Term B Loans; • The issuance of new notes to Holders of Allowed Second Lien Notes Claims in an aggregate principal amount of approximately $78.1 million , plus accrued and unpaid post-petition interest through the Effective Date; • The GUC Rights Offering is in an amount equal to 21.9% of the total amount of all Allowed General Unsecured Claims and Allowed Encana Claims; provided that in no event shall the GUC Rights Offering Amount exceed (a) with respect to Holders of Allowed General Unsecured Claims, $7.7 million (such amount to be reduced, pro rata, for the proportion of General Unsecured Claims for which an election to participate in the GUC Cash Pool was made) and (b) with respect to Encana, 21.9% of the amount of the Allowed Encana Claims (such amount to be reduced to reflect the same final rate, as a percentage of Allowed Claims, at which Holders of Allowed General Unsecured Claims electing to receive distributions from the GUC Equity Pool are able to subscribe for in the GUC Rights Offering in accordance with the GUC Rights Offering Procedures); • With respect to holders of VNR Preferred Units, on the Effective Date, except to the extent that a Holder of VNR Preferred Units agrees to less favorable treatment of its VNR Preferred Units, and subject to the terms of the Restructuring Transactions, all VNR Preferred Units shall be cancelled and shall be of no further force and effect, whether surrendered for cancellation or otherwise, and in full and final satisfaction, settlement, release, and discharge of and in exchange for each VNR Preferred Unit, each Holder of VNR Preferred Units shall receive: (a) if Class 6, Class 7, Class 8, Class 9, and Class 12 are each determined to have voted to accept the Plan in accordance with the Bankruptcy Code, such Holder’s Pro Rata share of (i) the VNR Preferred Unit Equity Distribution and (ii) VNR Preferred Unit New Warrants; or (b) if Class 6, Class 7, Class 8, Class 9, or Class 12 is determined to have voted to reject the Plan in accordance with the Bankruptcy Code, no distribution; provided that each Holder of VNR Preferred Units shall be given the opportunity to elect to waive its recovery, in which case the VNR Preferred Unit Equity Distribution and three year VNR Preferred Unit New Warrants that such Holder would have been entitled to receive shall be cancelled and of no further effect; and • With respect to holders of VNR Common Units, on the Effective Date, except to the extent that a Holder of VNR Common Units agrees to less favorable treatment of its VNR Common Units, and subject to the terms of the Restructuring Transactions, all VNR Common Units shall be cancelled and shall be of no further force and effect, whether surrendered for cancellation or otherwise, and in full and final satisfaction, settlement, release, and discharge of and in exchange for each VNR Common Unit, each Holder of VNR Common Units shall receive: (a) if Class 6, Class 7, Class 8, Class 9, Class 12, and Class 13 are each determined to have voted to accept the Plan in accordance with the Bankruptcy Code, such Holder’s Pro Rata share of three year VNR Common Unit New Warrants; or (b) if Class 6, Class 7, Class 8, Class 9, Class 12, or Class 13 is determined to have voted to reject the Plan in accordance with the Bankruptcy Code, no distribution; provided that each Holder of VNR Common Units shall be given the opportunity to elect to waive its recovery, in which case the VNR Common Unit New Warrants that such Holder would have been entitled to receive shall be cancelled and of no further effect. Prior to the Effective Date, the Debtors were required to distribute waiver election forms to the Holders of VNR Preferred Units and VNR Common Units, pursuant to which the Holders elected to waive and decline any distribution on account of their VNR Preferred Units or VNR Common Units, as applicable. These waiver election forms set forth instructions for such Holders to either (i) electronically deliver their VNR Preferred Unit or VNR Common Unit positions through The Depository Trust Company's Automated Tender Offer Program (if the Holder held its VNR Preferred Units or VNR Common Units through a Nominee) or (ii) mark such election on the form and return the form to Prime Clerk LLC (if the VNR Preferred Units or VNR Common Units, as applicable, were held directly in the Holder’s name on the books and records of the stock transfer agent and not through a nominee). The Amended RSA obligated 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. Modified Second Amended Joint Plan of Reorganization On July 18, 2017 , the Bankruptcy Court entered the Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Confirmation Order”), which approved and confirmed the Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Final Plan”). The Final Plan provides for the reorganization of the Debtors as a going concern and will significantly reduce long-term debt and annual interest payments of the reorganized Debtors. The following is a summary of the material modifications of the Final Plan that were made to the Second Amended Joint of Plan of Reorganization described above. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Final Plan. • the issuance to holders of the Company’s Preferred Units of such holders’ pro rata share of (i) New Common Stock and (ii) three and a half year VNR Preferred Unit New Warrants to purchase additional shares of New Common Stock at a strike price of $44.25 ; and • the issuance to the Company’s common unitholders of such holders’ pro rata share of three and a half year VNR Common Unit New Warrants to purchase shares of New Common Stock at a strike price of $61.45 , regardless of whether the holders of the Company’s common units voted to accept the Plan. The warrant strike prices were calculated based on the Company’s plan equity value of $20.00 per share of New Common Stock, which the Bankruptcy Court confirmed as part of the Plan. Unless otherwise specified, the treatment set forth in the Final Plan and Confirmation Order will be in full satisfaction of all claims against and equity interests in the Debtors, which will be discharged on the Effective Date. Other than assumed obligations, all of the Debtors’ prepetition claims and equity interests will be discharged by the Plan. Additional information regarding the classification and treatment of claims and equity interests can be found in Article III of the Final Plan. The Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017 as the Effective Date. The Company reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Company’s equity securities outstanding immediately before the Effective Date (including any unvested restricted units held by employees or officers of the Debtor, or options and warrants to purchase such securities) have been canceled and are of no further force or effect as of the Effective Date. Under the Final Plan, the Debtors’ new organizational documents became effective on the Effective Date. The reorganized parent’s new organizational documents authorize the company to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Plan on the Effective Date. In addition, on the Effective Date, the Company entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Company had 20.1 million outstanding shares of common stock, $0.001 par value. (“Common Stock”). Emergence from Chapter 11 On the Effective Date, the Debtors substantially consummated the Plan and emerged from their Chapter 11 Cases. As part of the transactions undertaken pursuant to the Plan, the Predecessor transferred all of its membership interests in Vanguard Natural Gas, LLC (“VNG”), a Kentucky limited liability company, the Predecessor’s wholly owned first-tier subsidiary to the Successor (formerly known as VNR Finance Corp.). VNG directly or indirectly owned all of the other subsidiaries of the Predecessor. As a result of the foregoing and certain other transactions, the Successor is no longer a subsidiary of the Predecessor and now owns all of the former subsidiaries of the Predecessor. Following the end of the current fiscal year, we expect that the Predecessor will be dissolved. Following the completion of these transactions, the Company became the successor issuer to the Predecessor for purposes of and pursuant to Rule 15d-5 of the Exchange Act. Prior to the consummation of the transactions undertaken pursuant to the Plan, the Company (as VNR Finance Corp.) was the co-issuer of the Predecessor’s debt securities and did not have any independent assets or operations. As described below, the Predecessor’s Senior Notes due 2020 and Senior Notes due 2019 were cancelled pursuant to the Plan. However, the Successor issued, and its subsidiaries guaranteed, new second lien notes due 2024 in the aggregate principal amount of $80.7 million in satisfaction of certain claims of the holders of the Old Second Lien Notes co-issued by the Predecessor and Successor. Exit Facility VNG, as borrower, has entered into that certain Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Exit Facility”), by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Credit Agreement, the lenders party thereto agreed to provide VNG with $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loans”). The initial borrowing base available under the Credit Agreement as of the Effective Date is $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Credit Agreement as of the Effective Date is $850.0 million . The Credit Agreement also includes an additional $125.0 million senior secured term loan (the “Term Loan”). The next borrowing base redetermination is scheduled for August of 2018. The maturity date of the Exit Facility is February 1, 2021 with respect to the Revolving Loans and May 1, 2021 with respect to the Term Loan. Until the maturity date for the Term Loan, the Term Loan shall bear an interest rate equal to 6.50% for an Alternate Base Rate loan or 7.50% for a Eurodollar loan. Until the maturity date for the Revolving Loans, the Revolving Loans shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 1.75% to 2.75% , based on the borrowing base utilization percentage under the Exit Facility or (ii) adjusted LIBOR plus an applicable margin of 2.75% to 3.75% , based on the borrowing base utilization percentage under the Exit Facility. Unused commitments under the Exit Facility will accrue a commitment fee of 0.5% , payable quarterly in arrears. VNG may elect, at its option, to prepay any borrowing outstanding under the Revolving Loans without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Facility). VNG may be required to make mandatory prepayments of the Revolving Loans in connection with certain borrowing base deficiencies. Additionally, if (i) VNG has outstanding borrowings, undrawn letters of credit and reimbursement obligations in respect of letters of credit in excess of the aggregate revolving commitments or (ii) unrestricted cash and cash equivalents of VNG and the Guarantors (as defined below) exceeds $35.0 million as of the close of business on the most recently ended business day, VNG is also required to make mandatory prepayments, subject to limited exceptions. The obligations under the Exit Facility are guaranteed by the Successor and all of VNG’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of VNG’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of VNG’s and the Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of VNG, subject to certain limited exceptions. The Exit Facility contains certain customary representations and warranties, including, without limitation: organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; no borrowing base deficiency; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; locations of businesses and offices; properties and titles; maintenance of properties; gas imbalances; prepayments; marketing of production; swap agreements; use of proceeds; solvency; money laundering; anti-corruption laws and sanctions. The Exit Facility also contains certain affirmative and negative covenants, including, without limitation: delivery of financial statements; notices of material events; existence and conduct of business; payment of obligations; performance of obligations under the Exit Facility and the other loan documents; operation and maintenance of properties; maintenance of insurance; maintenance of books and records; compliance with laws and regulations; compliance with environmental laws and regulations; delivery of reserve reports; delivery of title information; requirement to grant additional collateral; compliance with ERISA; maintenance of commodity price risk management policy; requirement to maintain commodity swaps; maintenance of treasury management; restrictions on indebtedness; liens; dividends and distributions; repayment of permitted unsecured debt; amendments to certain agreements; investments; change in the nature of business; leases (including oil and gas property leases); sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; marketing activities; gas imbalances; take-or-pay or other prepayments; swap agreements and transactions, and passive holding company status. The Exit Facility also contains certain financial covenants, including the maintenance of (i) the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available of (a) 4.75 to 1.00 as of the last of any fiscal quarter ending from July 1, 2018 through December 31, 2018, (b) 4.50 to 1.00 as of the last day of any fiscal quarter ending from January 1, 2019 through December 31, 2019, (c) 4.25 to 1.00 as of the last day of any fiscal quarter ending from January 1, 2020 through September 30, 2020, and (d) 4.00 to 1.00 as of the last day of any fiscal quarter ending thereafter; (ii) an asset coverage ratio of not less than 1.25 to 1.00 as tested on each January 1 and July 1 for the period from August 1, 2017 until August 1, 2018; and (iii) a current ratio, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending December 31, 2017, of not less than 1.00 :1.00. The Exit Facility also contains certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. New Second Lien Notes Indenture On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of new 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes”) to certain eligible holders of their outstanding Old Second Lien Notes issued by the Predecessor and the Successor (the “Existing Notes”) in full satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The New Notes were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act. The New Notes are governed by an Amended and Restated Indenture, dated as of August 1, 2017 (as amended, the “Amended and Restated Indenture”), by and among the Company, certain subsidiary guarantors of the Company (the “Guarantors”) and Delaware Trust |
Acquisitions and Divestitures
Acquisitions and Divestitures | 6 Months Ended |
Jun. 30, 2017 | |
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 units or exchanged assets as described below. 2017 Divestitures On April 2017, we entered into a purchase and sale agreement, as amended, with a third party buyer for the sale of a substantial portion our oil and gas properties located in Glasscock County, Texas (the “Asset Sale”). The Asset Sale included the sale of leases with a purchase price of $96.9 million which we closed on May 19, 2017 and in a subsequent transaction on June 30, 2017, we closed the sale of wells related to the assets for an adjusted purchase price of $5.2 million , subject to customary post-closing adjustments. In accordance with the Final Plan as defined in Note 2, all net cash proceeds received from the Asset Sale were used to pay the lenders under the Reserve-Based Credit Facility on August 1, 2017, the Effective Date of the Final Plan. During the six months ended June 30, 2017 , we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $5.4 million . All cash proceeds received from the sales of these properties during the period were used to fund the Company’s operating and capital expenses as well as to cover the cost of the Chapter 11 Cases. 2016 Acquisitions 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 properties in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $270.5 million , subject to final post-closing adjustments (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 gas 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 gas properties were recognized and the sales proceeds were treated as an adjustment to the cost of the properties. Pro Forma Operating Results In accordance with ASC Topic 805, presented below are unaudited pro forma results for the six months ended June 30, 2016 to show the effect on our consolidated results of operations as if the SCOOP/STACK Divestiture completed in 2016 had occurred on January 1, 2015 . The pro forma results reflect the elimination of the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations: Pro Forma Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 (in thousands, except per unit data) Total revenues $ 67,655 $ 215,426 Net loss attributable to Vanguard unitholders $ (801,885 ) $ (931,913 ) Net loss per unit Common and Class B units - basic and diluted $ (9.29 ) $ (10.93 ) 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: Pro Forma Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 (in thousands) Revenues $ 7,386 $ 17,542 Excess of revenues over direct operating expenses $ 6,222 $ 15,278 |
Debt
Debt | 6 Months Ended |
Jun. 30, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our financing arrangements consisted of the following as of the date indicated: Amount Outstanding Description Interest Rate Maturity Date June 30, 2017 December 31, 2016 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,248,795 $ 1,269,000 Senior Notes due 2019 8.375% (2) June 1, 2019 51,120 51,120 Senior Notes due 2020 7.875% (3) April 1, 2020 381,830 381,830 Senior Notes due 2023 7.00% February 15, 2023 75,634 75,634 Lease Financing Obligation 4.16% August 10, 2020 (4) 17,845 20,167 Unamortized discount on Senior Notes — (13,167 ) Unamortized deferred financing costs (5,272 ) (11,072 ) Total debt $ 1,769,952 $ 1,773,512 Less: Long-term debt classified as current (1,319,157 ) (1,753,345 ) Liabilities subject to compromise (Note 2) (432,950 ) — Current portion of Lease Financing Obligation (4,790 ) (4,692 ) Total long-term debt $ 13,055 $ 15,475 (1) Variable interest rate was 3.59% and 3.11% at June 30, 2017 and December 31, 2016 , respectively. (2) Effective interest rate was 21.45% at June 30, 2017 and December 31, 2016 . (3) Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016 . (4) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. Acceleration of Debt Obligations The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted 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. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures were stayed automatically as a result of the filing of the Bankruptcy 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. Amounts outstanding under our prepetition Reserve-Based Credit Facility and Senior Secured Second Lien Notes have been reclassified as current liabilities in the consolidated balance sheet as of June 30, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. These amounts have not been classified as liabilities subject to compromise as we believe the values of the underlying assets provide sufficient collateral to satisfy such obligations. In addition, the unsecured obligations under our Senior Notes due in 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017. We accelerated the amortization of the remaining debt issue discount of $12.8 million and debt issue costs of $3.6 million associated with the Senior Notes due 2019 and Senior Notes due 2020, fully amortizing those amounts as of the Petition Date. We entered into a restructuring agreement with the Lenders under our Reserve-Based Credit Facility, along with the Restructuring Support Agreement with certain holders of the Senior Secured Second Lien Notes, that was approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of the remaining debt issue costs related to the Reserve-Based Credit Facility and Senior Secured Second Lien Notes. Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations , we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017 . In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $14.3 million , representing interest expense from the Petition Date through June 30, 2017 . We continue to accrue interest on the Reserve-Based Credit Facility and Senior Secured Second Lien Notes subsequent to the Petition Date since we anticipate such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. During the Chapter 11 Cases, we made interest payments under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest was paid to the holders of the Senior Secured Second Lien Notes subsequent to the Petition Date. Additional information regarding the Chapter 11 cases is included in Note 2. Chapter 11 Cases. 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 June 30, 2017 there were approximately $1.2 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $148.9 million under the Reserve-Based Credit Facility. The Reserve-Based Credit Facility was secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. Therefore, upon the acceleration as a consequence of the commencement of the Chapter 11 Cases, we reclassified the amount outstanding under our Reserve-Based Credit Facility to current portion of long-term debt, as the principal became immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions. Pursuant to the Final Plan, we entered into a new Company reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by the same lenders under the prepetition Reserve-Based Credit Facility. Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Credit Agreement were canceled and discharged, and the Successor entered into the Exit Facility. See Note 2 for more information. 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 included lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. Throughout the pendency of the Chapter 11 Cases, the Company did not access funds through the DIP Credit Agreement. Letters of Credit At June 30, 2017 , 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 natural 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 was 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 marketing counterparties. 8.375% Senior Notes Due 2019 At June 30, 2017 , we had $51.1 million outstanding in aggregate principal amount of Senior Notes due 2019. The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger. Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Senior Notes due 2019 were canceled and discharged. See Note 2 for more information. 7.875% Senior Notes Due 2020 At June 30, 2017 , we had $381.8 million outstanding in aggregate principal amount of Senior Notes due 2020. The issuers of the Senior Notes due 2020 were the Predecessor and the prepetition Successor, which at the time had no independent assets or operations. Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Senior Notes due 2020 were canceled and discharged. See Note 2 for more information. 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 our 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 the six months ended June 30, 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 . Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Old Second Lien Notes were canceled and discharged, and the Company issued the New Notes. See Note 2 for more information. Lease Financing Obligations On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and 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 current fair market value. The Lease Financing Obligations also contain an early buyout option whereby 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% . During the course of the Chapter 11 Cases, the Company assumed the Lease Financing Obligations. |
Price and Interest Rate Risk Ma
Price and Interest Rate Risk Management Activities | 6 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price and Interest Rate Risk Management Activities | Price and Interest Rate Risk Management Activities In October and December 2016, we monetized substantially all of our commodity and interest rate hedge agreements for total proceeds of approximately $54.0 million . We used the net proceeds from the hedge settlements to make the deficiency payments under our Reserve-Based Credit Facility. In June 2017, we 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 over hedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. We have also historically entered into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The following tables summarize oil, natural gas, and NGL commodity derivative contracts in place at June 30, 2017. Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average August 1, 2017 – December 31, 2017 22,950,000 $ 3.12 1,365,100 $ 45.20 627,300 $ 26.42 January 1, 2018 – December 31, 2018 48,800,000 $ 3.02 3,059,200 $ 46.47 1,350,500 $ 25.37 January 1, 2019 - December 31, 2019 20,637,500 $ 2.86 821,250 $ 47.42 — $ — January 1, 2020 - December 31, 2020 11,895,000 $ 2.79 622,200 $ 48.92 — $ — Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) January 1, 2019 - December 31, 2019 4,125,000 $ 2.60 $ 3.00 273,750 $ 42.50 $ 53.60 January 1, 2020 - December 31, 2020 5,490,000 $ 2.60 $ 3.00 219,600 $ 42.50 $ 56.10 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 as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): June 30, 2017 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 4,122 $ (4,122 ) $ — Total derivative instruments $ 4,122 $ (4,122 ) $ — Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (16,997 ) $ 4,122 $ (12,875 ) Total derivative instruments $ (16,997 ) $ 4,122 $ (12,875 ) December 31, 2016 Derivative Liabilities: Amount Presented in the Consolidated Balance Sheets Interest rate derivative contracts $ (125 ) Total derivative instruments $ (125 ) 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. All of our counterparties were 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 were not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $4.1 million at June 30, 2017 . We minimize the credit risk related to derivative instruments by: (i) entering into derivative instruments with counterparties that our also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis Changes in fair value of our commodity and interest rate derivatives for the six months ended June 30, 2017 and the year ended December 31, 2016 are as follows: Six Months Ended June 30, 2017 Year Ended December 31, 2016 (in thousands) Derivative liability at beginning of period, net $ (125 ) $ 316,691 Purchases Net premiums and fees received for derivative contracts — (2,444 ) Net losses on commodity and interest rate derivative contracts (12,838 ) (46,939 ) Settlements Cash settlements received on matured commodity derivative contracts (7 ) (226,876 ) Cash settlements paid on matured interest rate derivative contracts 95 13,398 Termination of derivative contracts — (53,955 ) Derivative liability at end of period, net $ (12,875 ) $ (125 ) |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2017 | |
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, recognition of asset retirement obligations 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. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding 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 represent their approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of June 30, 2017 , the fair value of our Senior Notes due 2020 was estimated to be $11.5 million , our Senior Notes due 2019 was estimated to be $3.1 million and our Senior Secured Second Lien Notes was estimated to be $74.3 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. Our commodity derivative instruments consist of fixed-price swaps and collars. 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 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 and ceilings 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. As of December 31, 2016, we had one remaining interest rate swap derivative contract, which expired in February 2017. 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. 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): June 30, 2017 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Liabilities: Commodity price derivative contracts $ (12,875 ) $ (12,875 ) Total derivative instruments $ (12,875 ) $ (12,875 ) December 31, 2016 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Liabilities: Interest rate derivative contracts $ (125 ) $ (125 ) Total derivative instruments $ (125 ) $ (125 ) The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy: Six Months Ended June 30, 2016 (in thousands) Unobservable inputs, beginning of period $ (5,933 ) Total gains 6,922 Settlements (3,225 ) Unobservable inputs, end of period $ (2,236 ) Change in fair value included in earnings related to derivatives still held as of June 30, $ 589 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. 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 six months ended June 30, 2017 , in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.3 million , at fair value and also recorded a $0.03 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the six months ended June 30, 2017 . During the year ended December 31, 2016 , in connection with the new wells drilled, we incurred and recorded asset retirement obligations totaling $0.7 million , at fair value. In addition, we recorded a $1.3 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 year ended December 31, 2016 . The fair value of additions to the asset retirement obligation liability is 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 4.7% and 5.5% ; and (4) the average inflation factor ranging between 1.8% and 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 | 6 Months Ended |
Jun. 30, 2017 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The asset retirement obligations as of June 30, 2017 and December 31, 2016 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2017 and the year ended December 31, 2016 were as follows: June 30, 2017 December 31, 2016 (in thousands) Asset retirement obligations, beginning of period $ 272,436 $ 271,456 Liabilities added during the current period 299 713 Accretion expense 5,813 12,145 Retirements (946 ) (2,230 ) Liabilities related to assets divested (8,160 ) (10,915 ) Change in estimate (29 ) 1,267 Asset retirement obligation, end of period 269,413 272,436 Less: current obligations (8,400 ) (7,884 ) Long-term asset retirement obligation, end of period $ 261,013 $ 264,552 Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the six months ended June 30, 2017 and year ended December 31, 2016 , the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $0.03 million and increased its estimates of future asset retirement obligations by $1.3 million , respectively, to reflect revised estimates to be incurred for plugging and abandonment costs. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Transportation Demand Charges As of June 30, 2017 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from four months to three 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 June 30, 2017 . 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. June 30, 2017 (in thousands) July 1, 2017 - December 31, 2017 $ 760 2018 1,009 2019 820 2020 410 Total $ 2,999 As part of our Chapter 11 Cases, we rejected significant contracts for transportation via the Rockies Express Pipeline and the East Tennessee Natural Gas Pipeline. These rejected contracts total $24.9 million in gross future minimum transportation demand charges and are not included in the table above. We have accrued the amounts due to these parties of $20.0 million representing our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases. The accruals are reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017 . 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) our merger with LRR Energy, L.P. (the “LRE Merger Litigation”), and (ii) our exchange (the Debt Exchange) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 4. Debt of the Notes to the Consolidated Financial Statements for further discussion). Since the filing of our 2016 Annual Report on Form 10-K, there have been no material developments with respect to the legal proceedings related to the Debt Exchange litigation. With respect to the LRE Merger Litigation, the court in the LRE Merger Litigation has denied the defendants’ motion to dismiss and set the lawsuit for a one-week jury trial beginning on February 11, 2019. The parties are currently engaged in the pre-trial discovery process. For more information concerning the LRE Merger Litigation, please see our 2016 Annual Report on Form 10-K. Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed as to the debtors, subject to reinstatement when either the Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 2. Chapter 11 Cases for information regarding our Chapter 11 Cases. 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_ Deficit and Net Loss p
Members’ Deficit and Net Loss per Common and Class B Unit | 6 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
Members’ Deficit and Net Loss per Common and Class B Unit | Members’ Deficit and Net Loss per Common and Class B Unit Effect of Filing on Unitholders Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units, Series C Preferred Units and Common and Class B Units are entitled to receive any distribution or retain any property under a plan of reorganization. Our common units, Class B units and Preferred Units were accounted for at their carrying value through the Effective Date of the reorganization. Cumulative Preferred Units The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2017 and December 31, 2016 : June 30, 2017 December 31, 2016 Earliest Redemption Date Liquidation Preference Per Unit 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 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. As a result of the Chapter 11 Cases, we stopped accruing dividends on Preferred Units as of the Petition date. As of June 30, 2017, dividends in arrears related to our Preferred Units were $5.1 million , $13.3 million and $8.3 million , respectively. Pursuant to the Plan, on the Effective Date, the Preferred Units were canceled. See Note 2 for more information. 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. The following is a summary of the changes in our common units issued during the six months ended June 30, 2017 and the year ended December 31, 2016 (in thousands): June 30, 2017 December 31, 2016 Beginning of period 131,009 130,477 Unit-based compensation (30 ) 532 End of period 130,979 131,009 There was no change in issued and outstanding Class B units during the six months ended June 30, 2017 or the year ended December 31, 2016 . Pursuant to the Plan, on the Effective Date, the common units and Class B units were canceled. See Note 2 for more information. Net Loss per Common and Class B Unit Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “ Earnings Per Share ” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, 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 basic net income (loss) per unit. For the three months ended June 30, 2017 and 2016, 13,472,608 and 2,633,333 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position. For the six months ended June 30, 2017 and 2016, 13,562,608 and 2,633,333 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were also 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. Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Preferred Units effective with the February 2016 distribution. 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 |
Unit-Based Compensation
Unit-Based Compensation | 6 Months Ended |
Jun. 30, 2017 | |
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 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 were able to 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 were outstanding. The fair value of restricted unit and phantom unit awards was 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 were required to be settled in units were recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company had the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognized 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 was 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 On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “2016 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 2016 Agreements were effective January 1, 2016 and the initial term of the 2016 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 2016 Agreements provide for the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As a result of the Chapter 11 Cases, the executive officers did not receive a payout of any compensation related to the performance-based cash bonus award in 2017. However, we recognized total compensation expense related to these arrangements of $0.5 million and $0.7 million for the three months ended June 30, 2017 and 2016 , respectively, and $1.0 million and $1.2 million for the six months ended June 30, 2017 and 2016 , respectively, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations. In addition, as of June 30, 2017 , we recognized an accrued liability of $1.4 million for the unpaid performance-based cash bonus award including a $0.4 million accrual for the unpaid portion of the 2016 performance-based cash bonus award. The accrual is included in liabilities subject to compromise on the Consolidated Balance Sheets as of June 30, 2017. Under the 2016 Agreements, the executives were also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Any restricted units and phantom units granted to executives under the 2016 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 included tandem grant of DERs. Pursuant to the Final Plan, all unvested equity grants outstanding immediately before the Effective Date were canceled and are of no further force or effect as of the Effective Date. Pursuant to the Plan, on the Effective Date, the Successor entered into the Amended and Restated Employment Agreements with Messrs. Smith, Robert and Pence. See Note 2 for more information. Unit Grants In January 2017, the executives were granted a total of 10,611,940 phantom units in accordance with the 2016 Agreements. Also, during the six months ended June 30, 2017 , our three independent board members were granted a total of 480,768 phantom units which were intended to vest one year from the date of grant. Restricted Units A summary of the status of the non-vested restricted units as of June 30, 2017 is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested restricted units at December 31, 2016 647,784 $ 19.14 Forfeited (11,958 ) $ 17.69 Vested (257,497 ) $ 20.80 Non-vested restricted units at June 30, 2017 378,329 $ 18.07 At June 30, 2017 , there was approximately $2.4 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately less than a year. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $0.9 million and $1.4 million in the selling, general and administrative expenses line item for the three months ended June 30, 2017 and 2016 , respectively, and $1.7 million and $2.6 million for the six months ended June 30, 2017 and 2016 , respectively. Phantom Units A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2017 is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested phantom units at December 31, 2016 3,628,529 $ 2.96 Granted 11,092,708 $ 0.67 Forfeited (54,562 ) $ 2.11 Vested (956,830 ) $ 4.31 Non-vested phantom units at June 30, 2017 13,709,845 $ 1.02 At June 30, 2017 , there were approximately $10.7 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.6 years . Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $1.6 million and $1.2 million in the selling, general and administrative expense line item for the three months ended June 30, 2017 and 2016 , respectively, and $3.4 million and $2.4 million for the six months ended June 30, 2017 and 2016 , respectively. Effect of Emergence from Bankruptcy on Unit-Based Compensation Pursuant to the Final Plan, all unvested equity grants outstanding immediately before the Effective Date were canceled and of no further force or effect as of the Effective Date. In addition, on the Effective Date, the VNR LTIP was canceled and extinguished, and participants in the VNR LTIP received no payment or other distribution on account of the VNR LTIP. |
Shelf Registration Statements
Shelf Registration Statements | 6 Months Ended |
Jun. 30, 2017 | |
Shelf Registration Statements [Abstract] | |
Shelf Registration Statements | 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. Finally, the Company had previously registered an indeterminate amount of common units, Preferred Units, debt securities and guarantees of debt securities under a registration statement on Form S-3, as amended (File No. 333-202064). Following the Effective Date, the Company filed post-effective amendments to the shelf registration statements to deregister the securities. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation The consolidated financial statements as of June 30, 2017 and December 31, 2016 and for the three and six months ended June 30, 2017 and 2016 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. 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 Cases On February 1, 2017 (the “Petition 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. Please read Note 2. Chapter 11 Cases for a discussion of the Chapter 11 Cases (as defined in Note 2). For periods subsequent to filing the Bankruptcy Petitions (as defined in Note 2), we have prepared our consolidated financial statements in accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. |
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 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 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 future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, 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 six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. No ceiling test impairment was required during the six months ended June 30, 2017 . When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. |
Goodwill and Intangible Assets | Goodwill and Other Intangible Assets We account for goodwill 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. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) (ASU 2017-04) to simplify the accounting for goodwill impairment. The guidance eliminated the need for Step 2 of the goodwill impairment test, which required 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 eliminated the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. We elected to early adopt ASU 2017-04 for the quarter ended March 31, 2017. We did not record any goodwill impairment during the six months ended June 30, 2017 since the carrying value of our reporting unit was negative at June 30, 2017 . |
New Pronouncements 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, other than additional disclosures, 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, 2016, 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 add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU No. 2017-01). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. This ASU will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and should be applied prospectively. The Company is currently evaluating the provisions of ASU 2017-01 and assessing the impact adoption may have on our consolidated financial statements. Currently, we do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements, however these amendments could result in the recording of fewer business combinations in future periods |
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 and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and 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. |
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 Quarterly Report on Form 10-Q. |
Chapter 11 Cases Chapter 11 Cas
Chapter 11 Cases Chapter 11 Cases (Liabilities Subject to Compromise) (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Liabilities Subject to Compromise [Abstract] | |
Schedule of Liabilities Subject to compromise | June 30, 2017 (in thousands) Accounts payable $ 1,942 Accrued liabilities 30,639 Senior notes and accrued interest 443,687 Liabilities subject to compromise $ 476,268 |
Schedule of Reorganization Items | Six Months Ended June 30, 2017 (in thousands) Professional and legal fees (1) $ 34,808 Deferred financing costs and debt discount (2) 16,444 Claims for non-performance of executory contracts (3) 28,715 Total Reorganization items $ 79,967 |
Chapter 11 Cases Chapter 11 C22
Chapter 11 Cases Chapter 11 Cases (Emergence from Chapter 11) (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Debt Instrument Redemption [Table Text Block] | On or after February 15, 2020, the New Notes will be redeemable, in whole or in part, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest: Year Percentage 2020 106.75 % 2021 104.50 % 2022 102.25 % 2023 and thereafter 100.00 % |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Business Combinations [Abstract] | |
Pro Forma Information | The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations: Pro Forma Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 (in thousands, except per unit data) Total revenues $ 67,655 $ 215,426 Net loss attributable to Vanguard unitholders $ (801,885 ) $ (931,913 ) Net loss per unit Common and Class B units - basic and diluted $ (9.29 ) $ (10.93 ) 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: Pro Forma Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 (in thousands) Revenues $ 7,386 $ 17,542 Excess of revenues over direct operating expenses $ 6,222 $ 15,278 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Debt Disclosure [Abstract] | |
Financing Arrangements | Our financing arrangements consisted of the following as of the date indicated: Amount Outstanding Description Interest Rate Maturity Date June 30, 2017 December 31, 2016 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,248,795 $ 1,269,000 Senior Notes due 2019 8.375% (2) June 1, 2019 51,120 51,120 Senior Notes due 2020 7.875% (3) April 1, 2020 381,830 381,830 Senior Notes due 2023 7.00% February 15, 2023 75,634 75,634 Lease Financing Obligation 4.16% August 10, 2020 (4) 17,845 20,167 Unamortized discount on Senior Notes — (13,167 ) Unamortized deferred financing costs (5,272 ) (11,072 ) Total debt $ 1,769,952 $ 1,773,512 Less: Long-term debt classified as current (1,319,157 ) (1,753,345 ) Liabilities subject to compromise (Note 2) (432,950 ) — Current portion of Lease Financing Obligation (4,790 ) (4,692 ) Total long-term debt $ 13,055 $ 15,475 (1) Variable interest rate was 3.59% and 3.11% at June 30, 2017 and December 31, 2016 , respectively. (2) Effective interest rate was 21.45% at June 30, 2017 and December 31, 2016 . (3) Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016 . (4) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. |
Price and Interest Rate Risk 25
Price and Interest Rate Risk Management Activities (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments [Table Text Block] | The following tables summarize oil, natural gas, and NGL commodity derivative contracts in place at June 30, 2017. Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average August 1, 2017 – December 31, 2017 22,950,000 $ 3.12 1,365,100 $ 45.20 627,300 $ 26.42 January 1, 2018 – December 31, 2018 48,800,000 $ 3.02 3,059,200 $ 46.47 1,350,500 $ 25.37 January 1, 2019 - December 31, 2019 20,637,500 $ 2.86 821,250 $ 47.42 — $ — January 1, 2020 - December 31, 2020 11,895,000 $ 2.79 622,200 $ 48.92 — $ — Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) January 1, 2019 - December 31, 2019 4,125,000 $ 2.60 $ 3.00 273,750 $ 42.50 $ 53.60 January 1, 2020 - December 31, 2020 5,490,000 $ 2.60 $ 3.00 219,600 $ 42.50 $ 56.10 |
Fair Value of Derivatives Outstanding | The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): June 30, 2017 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 4,122 $ (4,122 ) $ — Total derivative instruments $ 4,122 $ (4,122 ) $ — Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (16,997 ) $ 4,122 $ (12,875 ) Total derivative instruments $ (16,997 ) $ 4,122 $ (12,875 ) December 31, 2016 Derivative Liabilities: Amount Presented in the Consolidated Balance Sheets Interest rate derivative contracts $ (125 ) Total derivative instruments $ (125 ) |
Reported Gains and Losses on Derivative Instruments | Changes in fair value of our commodity and interest rate derivatives for the six months ended June 30, 2017 and the year ended December 31, 2016 are as follows: Six Months Ended June 30, 2017 Year Ended December 31, 2016 (in thousands) Derivative liability at beginning of period, net $ (125 ) $ 316,691 Purchases Net premiums and fees received for derivative contracts — (2,444 ) Net losses on commodity and interest rate derivative contracts (12,838 ) (46,939 ) Settlements Cash settlements received on matured commodity derivative contracts (7 ) (226,876 ) Cash settlements paid on matured interest rate derivative contracts 95 13,398 Termination of derivative contracts — (53,955 ) Derivative liability at end of period, net $ (12,875 ) $ (125 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis | December 31, 2016 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Liabilities: Interest rate derivative contracts $ (125 ) $ (125 ) Total derivative instruments $ (125 ) $ (125 ) |
Reconciliation of changes in the fair value of 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 (unobservable inputs) in the fair value hierarchy: Six Months Ended June 30, 2016 (in thousands) Unobservable inputs, beginning of period $ (5,933 ) Total gains 6,922 Settlements (3,225 ) Unobservable inputs, end of period $ (2,236 ) Change in fair value included in earnings related to derivatives still held as of June 30, $ 589 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Asset Retirement Obligation [Abstract] | |
Changes in Asset Retirement Obligations | The asset retirement obligations as of June 30, 2017 and December 31, 2016 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2017 and the year ended December 31, 2016 were as follows: June 30, 2017 December 31, 2016 (in thousands) Asset retirement obligations, beginning of period $ 272,436 $ 271,456 Liabilities added during the current period 299 713 Accretion expense 5,813 12,145 Retirements (946 ) (2,230 ) Liabilities related to assets divested (8,160 ) (10,915 ) Change in estimate (29 ) 1,267 Asset retirement obligation, end of period 269,413 272,436 Less: current obligations (8,400 ) (7,884 ) Long-term asset retirement obligation, end of period $ 261,013 $ 264,552 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Future minimum transportation demand charges | The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of June 30, 2017 . 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. June 30, 2017 (in thousands) July 1, 2017 - December 31, 2017 $ 760 2018 1,009 2019 820 2020 410 Total $ 2,999 |
Members_ Deficit and Net Loss29
Members’ Deficit and Net Loss per Common and Class B Unit (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
Cumulative Preferred Units | The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2017 and December 31, 2016 : June 30, 2017 December 31, 2016 Earliest Redemption Date Liquidation Preference Per Unit 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 |
Schedule of Common and Class B Units Outstanding Roll Forward | The following is a summary of the changes in our common units issued during the six months ended June 30, 2017 and the year ended December 31, 2016 (in thousands): June 30, 2017 December 31, 2016 Beginning of period 131,009 130,477 Unit-based compensation (30 ) 532 End of period 130,979 131,009 |
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. Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Preferred Units effective with the February 2016 distribution. 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 |
Unit-Based Compensation (Tables
Unit-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | cted Units A summary of the status of the non-vested restricted units as of June 30, 2017 is presen |
Schedule of Nonvested Phantom Units Activity | ntom Units A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2017 is presen |
Description of the Business (De
Description of the Business (Details) $ in Millions | 6 Months Ended | |
Jun. 30, 2017operating_areas | Aug. 01, 2017USD ($) | |
Number of operating areas | operating_areas | 10 | |
Subsequent Event [Member] | ||
Postconfirmation, Common Stock | $ | $ 20.1 |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Details) | Jun. 30, 2017 |
Potato Hills Gas Gathering System [Member] | |
Ownership interest percent | 51.00% |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Oil and Gas Properties) (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($)$ / bbl$ / MMBTU | Mar. 31, 2016USD ($)$ / bbl$ / MMBTU | Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | |
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 | $ | $ 0 | $ 157,894 | $ 207,800 | $ 0 | $ 365,658 |
Average price of natural gas used in the impairment calculation | $ / MMBTU | 2.24 | 2.41 | |||
Average price of crude oil used in the impairment calculation | $ / bbl | 42.91 | 46.16 |
Chapter 11 Cases (Commencement
Chapter 11 Cases (Commencement of Bankruptcy Cases) (Details) | Feb. 01, 2017 |
Chapter 11 Cases [Abstract] | |
Bankruptcy Proceedings, Date Petition for Bankruptcy Filed | Feb. 1, 2017 |
Chapter 11 Cases (Creditors' Co
Chapter 11 Cases (Creditors' Committees - Appointment & Formation) (Details) | Jun. 30, 2017 | [1] | Feb. 01, 2017 | Dec. 31, 2016 |
Senior Notes due 2020 [Member] | ||||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 52.00% | |||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | 7.875% | 7.875% | |
Senior Notes due 2019 [Member] | ||||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 10.00% | |||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | |||
Subordinated Debt due 2023 | ||||
Percentage Of Principal Amount Of Debt Held By Restructuring Support Parties | 92.00% | |||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | |||
[1] | Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016. |
Chapter 11 Cases (Schedules and
Chapter 11 Cases (Schedules and Statements-Claims) (Details) - Subsequent Event [Member] $ in Billions | 6 Months Ended |
Aug. 02, 2017USD ($)ClaimantsClaims | |
Bankruptcy Claims, Number Claims Filed | Claims | 1,040 |
Bankruptcy Claims, Amount of Claims Filed | $ | $ 19.5 |
Bankruptcy Claims, Number of Claimants | Claimants | 800 |
Chapter 11 Cases (Joint Plan of
Chapter 11 Cases (Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code) (Details) | Feb. 01, 2017USD ($) | Mar. 31, 2017 | May 31, 2017USD ($) |
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 | $ 78,100,000 | |
Credit term extension period | 12 months | ||
Basis Points Increase in Debt Securities Interest Rate | 0.02 | ||
Warrant Exercise Period | 3 years 6 months | ||
Plan of Reorganization, Principal Amount of Senior Note Rights Offering | $ 255,750,000 | ||
Plan of Reorganization, Amount of equity investment commitment | $ 19,250,000 | ||
Discount on New Equity Security Issue Price | 25.00% | ||
Percentage of new equity interests reserved for grants | 10.00% | ||
Line of Credit, New Facility [Member] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,100,000,000 | ||
Senior Note Holder [Member] | |||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 97.00% | ||
Preferred Unit Holder [Member] | |||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 3.00% |
Chapter 11 Cases (Second Amende
Chapter 11 Cases (Second Amended Joint Plan of Reorganization) (Details) - USD ($) | Feb. 01, 2017 | May 31, 2017 |
Warrant Exercise Period | 3 years 6 months | |
Plan of Reorganization, Principal Amount of Senior Note Rights Offering | $ 255,750,000 | |
Section 4(a)(2) backstop commitment amount | $ 127,900,000 | |
Plan of Reorganization, Amount of equity investment commitment | 19,250,000 | |
Plan of Reorganization, Amount of Debt Securities to be Issued | $ 75,600,000 | $ 78,100,000 |
Percentage GUC Rights Offering over total Allowed GUCs and Allowed Encana Claims | 22.00% | |
Maximum amount of GUC Rights Offering to be issued to Holders of Allowed GUCs | $ 7,700,000 | |
Maximum GUC Rights Offering to be issued to Holders of Allowed Encana Claims as a percentage of the Allowed Encana Claims | 22.00% | |
Senior Notes Claims Rights Offering Holders [Member] | ||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 84.80% | |
Second Lien Investors [Member] | ||
Plan Of Reorganization, Percentage Of Pro-rata Share To Be Received By Holders Of Bankruptcy Claim | 6.40% | |
Section 1145 Rights Offering [Member] | ||
Plan of Reorganization, Principal Amount of Senior Note Rights Offering | $ 10,176,081 | |
Accredited Investor Rights Offering [Member] | ||
Plan of Reorganization, Principal Amount of Senior Note Rights Offering | $ 117,698,919 |
Chapter 11 Cases (Modified Seco
Chapter 11 Cases (Modified Second Amendment Joint Plan of Reorganization) (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions | Jul. 18, 2017 | Aug. 01, 2017 |
Plan of Reorganization, Date Plan Confirmed | Jul. 18, 2017 | |
Equity Value per share | $ 20 | |
Postconfirmation, Common Stock | $ 20.1 | |
Common Stock, Par or Stated Value Per Share | $ 0.001 | |
VNR Preferred Unit New Warrant [Member] | ||
Class of Warrant or Right, Exercise Price of Warrants or Rights | 44.25 | |
VNR Common Unit New Warrant [Member] | ||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 61.45 |
Chapter 11 Cases (Emergence fro
Chapter 11 Cases (Emergence from Chapter 11) (Details) - USD ($) $ / shares in Units, $ in Thousands | Jan. 01, 2023 | Jan. 01, 2018 | Aug. 01, 2017 | Jun. 30, 2017 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Jan. 01, 2020 | Jan. 01, 2019 | Jul. 01, 2018 | Jul. 18, 2017 | Dec. 31, 2016 |
Debt amount outstanding | $ 1,769,952 | $ 1,773,512 | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,100,000 | |||||||||||
Series A Preferred Units | ||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.875% | |||||||||||
Series B Preferred Unit | ||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.625% | |||||||||||
Series C Preferred Units | ||||||||||||
Preferred Unit, Distribution Rate, Percentage | 7.75% | |||||||||||
Subsequent Event [Member] | ||||||||||||
Debt Instrument, Redemption Price, Percentage, subsequent to equity offering | 100.00% | |||||||||||
Standstill period for Collateral Trustee to enforce rights or remedies | 180 days | |||||||||||
Period to file Initial Registration Statement after Emergence Date | 90 days | |||||||||||
Percentage of Registration Rights Holders required to file the initial registration statement | 20.00% | |||||||||||
Claims, Holders of Old Second Lien Notes | $ 80,700 | |||||||||||
Percentage of aggregate principal debt representing holders who can declare the debt due immediately upon default | 25.00% | |||||||||||
Percentage of Principal Senior Notes than can be redeemed before February 15, 2020 | 35.00% | |||||||||||
Debt Instrument, Redemption Price, Percentage | 109.00% | |||||||||||
Percentage of Principal Amount of Senior Notes to remain outstanding on February 2020 | 65.00% | |||||||||||
Debt Instrument, Redemption Period, Number of days from equity offering | 180 days | |||||||||||
Limit on unrestricted cash | $ 35,000 | |||||||||||
Lien on oil and gas properties, Percentage | 95.00% | |||||||||||
Debt Instrument, Covenant, Debt to EBITDA ratio | 475.00% | |||||||||||
Asset coverage ratio | 125.00% | |||||||||||
Debt Instrument, Covenant, Current Ratio | 100.00% | |||||||||||
Executive Employment Agreement extension period | 12 months | |||||||||||
Period following change of control executives receive compensation if terminated without cause or resigns for good reason | 12 months | |||||||||||
Period executives to receive compensation following change of control and subsequent termination without cause or resigns for good reason | 10 days | |||||||||||
Period executives to receive lump sum compensation following change of control and subsequent termination without cause ore resigns for good reason | 60 days | |||||||||||
Executive annual base salary and bonus multiplier, Basis for lump sum payment to executives following change of control and subsequent termination without cause or resignation for good reason | 2 | |||||||||||
Period executives to receive severance payments following change of control and subsequent termination without cause ore resigns for good reason | 60 days | |||||||||||
Executive annual base salary and bonus multiplier, Basis for severance payment to executives following change of control and subsequent termination without cause or resignation for good reason | 2.5 | |||||||||||
Cure period for breach of executive employment agreement | 10 days | |||||||||||
Period following Effective Date initial grants to be made under the Management Incentive Plan | 90 days | |||||||||||
Number of consecutive days within disability period as defined in the executive employment agreement | 180 days | |||||||||||
Disability period as defined in the executive employment agreement | 12 days | |||||||||||
Subsequent Event [Member] | Second Lien Notes Due 2024 [Member] | ||||||||||||
Debt amount outstanding | $ 80,700 | |||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.00% | |||||||||||
Subsequent Event [Member] | Exit Revolving Credit Facility [Member] | ||||||||||||
Debt amount outstanding | $ 850,000 | |||||||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | |||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 850,000 | |||||||||||
Subsequent Event [Member] | Exit Term Loan Facility [Member] | ||||||||||||
Debt amount outstanding | $ 125,000 | |||||||||||
Minimum | Alternative Base Interest Rate [Member] | Subsequent Event [Member] | Exit Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | |||||||||||
Minimum | Eurodollar Interest Rate [Member] | Subsequent Event [Member] | Exit Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 3.00% | |||||||||||
Maximum | Alternative Base Interest Rate [Member] | Subsequent Event [Member] | Exit Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 3.00% | |||||||||||
Maximum | Eurodollar Interest Rate [Member] | Subsequent Event [Member] | Exit Revolving Credit Facility [Member] | ||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 4.00% | |||||||||||
Scenario, Forecast [Member] | ||||||||||||
Debt Instrument, Redemption Price, Percentage | 100.00% | 102.00% | 105.00% | 107.00% | ||||||||
Debt Instrument, Covenant, Debt to EBITDA ratio | 400.00% | 425.00% | 450.00% | |||||||||
VNR Preferred Unit New Warrant [Member] | Subsequent Event [Member] | ||||||||||||
Class of Warrant or Right, Number of Securities Called by Each Warrant or Right | 621,649 | |||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 44.25 | |||||||||||
VNR Common Unit New Warrant [Member] | Subsequent Event [Member] | ||||||||||||
Class of Warrant or Right, Number of Securities Called by Each Warrant or Right | 640,876 | |||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 61.45 | |||||||||||
Scott Smith [Member] | Subsequent Event [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | $ 650 | |||||||||||
Executive Bonus paid out per the Reorganization Plan | 610 | |||||||||||
Scott Smith [Member] | Scenario, Forecast [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | $ 700 | |||||||||||
Richard Robert [Member] | Subsequent Event [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | 490 | |||||||||||
Executive Bonus paid out per the Reorganization Plan | 460 | |||||||||||
Richard Robert [Member] | Scenario, Forecast [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | 510 | |||||||||||
Britt Pence [Member] | Subsequent Event [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | 450 | |||||||||||
Executive Bonus paid out per the Reorganization Plan | $ 430 | |||||||||||
Britt Pence [Member] | Scenario, Forecast [Member] | ||||||||||||
Annual Base Salary per executive employment agreement | $ 460 | |||||||||||
Exit Term Loan Facility [Member] | Alternative Base Interest Rate [Member] | Subsequent Event [Member] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||||||
Exit Term Loan Facility [Member] | Eurodollar Interest Rate [Member] | Subsequent Event [Member] | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.50% |
Chapter 11 Cases (Debtor-in-Pos
Chapter 11 Cases (Debtor-in-Possession Financing) (Details) - USD ($) $ in Millions | Feb. 01, 2017 | Jun. 30, 2017 |
Debtor-in-Possession Financing, Amount Arranged | $ 50 | |
Preconfirmation, Debtor-in-Possession Financing, Interim Borrowing Capacity | 15 | |
Debtor in Possession Financing, maturity period | 45 days | |
Line of Credit Facility, Commitment Fee Percentage | 1.00% | |
Minimum amount of debtor unrestricted cash and DIP financing unused borrowing | $ 25 | |
London Interbank Offered Rate (LIBOR) [Member] | Debtor-in-Possession Financing [Member] | ||
Debt Instrument, Basis Spread on Variable Rate | 5.50% |
Chapter 11 Cases (Acceleration
Chapter 11 Cases (Acceleration of Debt Obligations) (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Feb. 01, 2017 | Dec. 31, 2016 |
Debt amount outstanding | $ 1,769,952 | $ 1,773,512 | |
Line of Credit Facility, Current Borrowing Capacity | 1,100,000 | ||
Line of Credit [Member] | |||
Debt amount outstanding | $ 1,250,000 | ||
Senior Notes due 2019 [Member] | |||
Debt amount outstanding | 51,120 | ||
Senior Notes due 2020 [Member] | |||
Debt amount outstanding | 381,830 | ||
Subordinated Debt due 2023 | |||
Debt amount outstanding | 75,630 | ||
Standby Letters of Credit [Member] | Line of Credit [Member] | |||
Line of Credit Facility, Current Borrowing Capacity | $ 200 | $ 200 |
Chapter 11 Cases (Liabilities S
Chapter 11 Cases (Liabilities Subject to Compromise) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | |
Liabilities Subject to Compromise [Abstract] | |||
Accounts payable | $ 1,942 | $ 1,942 | |
Accrued liabilities | 30,639 | 30,639 | |
Senior notes and accrued interest | 443,687 | 443,687 | |
Liabilities Subject to Compromise | 476,268 | 476,268 | $ 0 |
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | $ 8,600 | $ 14,300 |
Chapter 11 Cases (Reorganizatio
Chapter 11 Cases (Reorganization Items) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Reorganizations [Abstract] | ||||
Professional and legal fees | $ 34,808 | |||
Deferred financing costs and debt discount | 16,444 | |||
Claims for non-performance of executory contracts | 28,715 | |||
Reorganization Items | $ 53,221 | $ 0 | 79,967 | $ 0 |
Non cash reorganization items, Professional and Legal Fees | $ 13,600 |
Acquisitions and Divestitures45
Acquisitions and Divestitures (Details) - USD ($) $ in Thousands | May 19, 2017 | May 19, 2016 | Jan. 01, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 |
Business Acquisition [Line Items] | ||||||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 107,689 | $ 285,590 | ||||
Glasscock Divestiture-Leases [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Business acquisitions, Agreed purchase price | $ 96,900 | |||||
Glasscock Divestiture-Wells [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Business acquisitions, Agreed purchase price | $ 5,200 | |||||
Series of Individually Immaterial Business Acquisitions [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 5,400 | $ 28,200 | ||||
Potato Hills Gas Gathering System [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Ownership interest conveyed | 51.00% | |||||
Fair value of consideration transferred | $ 7,900 | |||||
SCOOP/STACK Divestiture [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Business acquisitions, Agreed purchase price | $ 270,500 | |||||
Transaction fees | 2,100 | |||||
Senior Secured Reserve-Based Credit Facility | SCOOP/STACK Divestiture [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Line of credit repayment | $ 268,400 |
Acquisitions and Divestitures P
Acquisitions and Divestitures Pro Forma Operating Results (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2016 | Jun. 30, 2016 | |
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | ||
Pro forma revenues | $ 67,655 | $ 215,426 |
Pro forma Net income | $ (801,885) | $ (931,913) |
Common and Class B units - basic and diluted (in USD per share) | $ (9.29) | $ (10.93) |
SCOOP/STACK Divestiture [Member] | ||
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | ||
Pro forma revenues | $ 7,386 | $ 17,542 |
Excess of revenues over direct operating expenses | $ 6,222 | $ 15,278 |
Debt (Details)
Debt (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | Feb. 01, 2017 | Feb. 10, 2016 | ||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 1,100,000,000 | $ 1,100,000,000 | ||||||||
Debt amount outstanding | 1,769,952,000 | 1,769,952,000 | $ 1,773,512,000 | |||||||
Senior Notes [Abstract] | ||||||||||
Extinguishment of Debt, Amount | 168,200,000 | |||||||||
Gain (Loss) on Extinguishment of Debt | 0 | $ 0 | $ 0 | $ 89,714,000 | ||||||
Carrying Value of Senior Notes exchanged, Net | $ 165,300,000 | |||||||||
Line of Credit [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate description | [1] | Variable (1) | ||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 3,500,000,000 | $ 3,500,000,000 | ||||||||
Debt amount outstanding | $ 1,250,000,000 | |||||||||
Long-term Line of Credit, Deficiency | $ (148,900,000) | $ (148,900,000) | ||||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Maturity Date | Apr. 16, 2018 | Apr. 16, 2018 | ||||||||
Senior Notes due 2019 [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 51,120,000 | |||||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | |||||||||
Senior Notes due 2020 [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 381,830,000 | |||||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | [2] | 7.875% | [2] | 7.875% | 7.875% | ||||
Lease Financing Obligations | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 17,845,000 | $ 17,845,000 | $ 20,167,000 | |||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.16% | 4.16% | 4.16% | |||||||
Aggregate Cost, Early Buyout Option to Purchase equipment | $ 16,000,000 | $ 16,000,000 | ||||||||
Debt Instrument, Maturity Date | Aug. 10, 2020 | [3] | Aug. 10, 2020 | |||||||
Standby Letters of Credit [Member] | Line of Credit [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | 200,000 | $ 200,000 | $ 200,000 | |||||||
Line of Credit [Member] | Line of Credit [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | 1,248,795,000 | 1,248,795,000 | $ 1,269,000,000 | |||||||
Senior Notes due 2019 [Member] | Senior Notes [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 51,120,000 | $ 51,120,000 | $ 51,120,000 | |||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | [4] | 8.375% | [4] | 8.375% | 8.375% | ||||
Debt Instrument, Maturity Date | Jun. 1, 2019 | Jun. 1, 2019 | ||||||||
Senior Notes due 2020 [Member] | Senior Notes [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 381,830,000 | $ 381,830,000 | $ 381,830,000 | |||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | |||||||||
Debt Instrument, Maturity Date | Apr. 1, 2020 | Apr. 1, 2020 | ||||||||
Senior Notes due 2023 [Member] | Senior Notes [Member] | ||||||||||
Senior Secured Reserve-Based Credit Facility [Abstract] | ||||||||||
Debt amount outstanding | $ 75,634,000 | $ 75,634,000 | $ 75,634,000 | |||||||
Senior Notes [Abstract] | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | 7.00% | 7.00% | 7.00% | ||||||
Debt Instrument, Maturity Date | Feb. 15, 2023 | Feb. 15, 2023 | ||||||||
[1] | Variable interest rate was 3.59% and 3.11% at June 30, 2017 and December 31, 2016, respectively. | |||||||||
[2] | Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016. | |||||||||
[3] | The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. | |||||||||
[4] | Effective interest rate was 21.45% at June 30, 2017 and December 31, 2016. |
Debt (Financing Arrangements) (
Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||||
Jun. 30, 2017 | Dec. 31, 2016 | Feb. 01, 2017 | Feb. 10, 2016 | |||
Debt Instrument [Line Items] | ||||||
Debt amount outstanding | $ 1,769,952 | $ 1,773,512 | ||||
Unamortized deferred financing costs | (5,272) | (11,072) | $ (3,600) | |||
Long-term debt classified as current | (1,319,157) | (1,753,345) | ||||
Liabilities Subject To Compromise Debt Only | (432,950) | 0 | ||||
Current portion of Lease Financing Obligation | (4,790) | (4,692) | ||||
Total long-term debt | $ 13,055 | $ 15,475 | ||||
Line of Credit [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate description | [1] | Variable (1) | ||||
Debt Instrument, Maturity Date | Apr. 16, 2018 | Apr. 16, 2018 | ||||
Debt amount outstanding | 1,250,000 | |||||
Variable interest rate | 3.59% | 3.11% | ||||
Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Unamortized discount on Senior Notes | $ 0 | $ (13,167) | $ (12,800) | |||
Senior Notes due 2020 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | [2] | 7.875% | 7.875% | ||
Debt amount outstanding | $ 381,830 | |||||
Senior Notes due 2019 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | |||||
Debt amount outstanding | $ 51,120 | |||||
Lease Financing Obligations | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.16% | 4.16% | ||||
Debt Instrument, Maturity Date | Aug. 10, 2020 | [3] | Aug. 10, 2020 | |||
Debt amount outstanding | $ 17,845 | $ 20,167 | ||||
Line of Credit [Member] | Line of Credit [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt amount outstanding | $ 1,248,795 | $ 1,269,000 | ||||
Senior Notes due 2019 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.375% | [4] | 8.375% | 8.375% | ||
Debt Instrument, Maturity Date | Jun. 1, 2019 | Jun. 1, 2019 | ||||
Debt amount outstanding | $ 51,120 | $ 51,120 | ||||
Debt Instrument, Interest Rate, Effective Percentage | 21.45% | 21.45% | ||||
Senior Notes due 2020 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.875% | |||||
Debt Instrument, Maturity Date | Apr. 1, 2020 | Apr. 1, 2020 | ||||
Debt amount outstanding | $ 381,830 | $ 381,830 | ||||
Debt Instrument, Interest Rate, Effective Percentage | 8.00% | 8.00% | ||||
Senior Notes due 2023 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | 7.00% | 7.00% | |||
Debt Instrument, Maturity Date | Feb. 15, 2023 | Feb. 15, 2023 | ||||
Debt amount outstanding | $ 75,634 | $ 75,634 | ||||
[1] | Variable interest rate was 3.59% and 3.11% at June 30, 2017 and December 31, 2016, respectively. | |||||
[2] | Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016. | |||||
[3] | The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. | |||||
[4] | Effective interest rate was 21.45% at June 30, 2017 and December 31, 2016. |
Debt (Acceleration of Debt Obli
Debt (Acceleration of Debt Obligations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2017 | Feb. 01, 2017 | Dec. 31, 2016 | |
Unamortized Debt Issuance Expense | $ 5,272 | $ 5,272 | $ 3,600 | $ 11,072 |
Liabilities subject to compromise, Accrued Interest Payable | 10,700 | 10,700 | ||
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | 8,600 | 14,300 | ||
Senior Notes [Member] | ||||
Debt Instrument, Unamortized Discount (Premium), Net | $ 0 | $ 0 | $ 12,800 | $ 13,167 |
Price and Interest Rate Risk 50
Price and Interest Rate Risk Management Activities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($) | Jun. 30, 2017MMBTU$ / bbl$ / MMBTUbbl | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Value of hedges monetized | $ | $ 54 | |
Natural Gas [Member] | Contract Period August 1 2017 to December 31 2017 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 22,950,000 | |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 3.12 | |
Natural Gas [Member] | Contract Period January 1 2018 to December 31 2018 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 48,800,000 | |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 3.02 | |
Natural Gas [Member] | Contract Period January 1 2019 to December 31 2019 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 20,637,500 | |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.86 | |
Natural Gas [Member] | Contract Period January 1 2019 to December 31 2019 [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 4,125,000 | |
Derivative, Floor Price | $ / MMBTU | 2.60 | |
Derivative, Cap Price | $ / MMBTU | 3 | |
Natural Gas [Member] | Contract Period January 1 2020 to December 31 2020 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 11,895,000 | |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.79 | |
Natural Gas [Member] | Contract Period January 1 2020 to December 31 2020 [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Portion of Future Gas Production Being Hedged | MMBTU | 5,490,000 | |
Derivative, Floor Price | $ / MMBTU | 2.60 | |
Derivative, Cap Price | $ / MMBTU | 3 | |
Oil [Member] | Contract Period August 1 2017 to December 31 2017 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,365,100 | |
Derivative, Swap Type, Average Fixed Price | 45.20 | |
Oil [Member] | Contract Period January 1 2018 to December 31 2018 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 3,059,200 | |
Derivative, Swap Type, Average Fixed Price | 46.47 | |
Oil [Member] | Contract Period January 1 2019 to December 31 2019 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 821,250 | |
Derivative, Swap Type, Average Fixed Price | 47.42 | |
Oil [Member] | Contract Period January 1 2019 to December 31 2019 [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 273,750 | |
Derivative, Floor Price | 42.50 | |
Derivative, Cap Price | 53.60 | |
Oil [Member] | Contract Period January 1 2020 to December 31 2020 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 622,200 | |
Derivative, Swap Type, Average Fixed Price | 48.92 | |
Oil [Member] | Contract Period January 1 2020 to December 31 2020 [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 219,600 | |
Derivative, Floor Price | 42.50 | |
Derivative, Cap Price | 56.10 | |
Natural Gas Liquids [Member] | Contract Period August 1 2017 to December 31 2017 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 627,300 | |
Derivative, Swap Type, Average Fixed Price | 26.42 | |
Natural Gas Liquids [Member] | Contract Period January 1 2018 to December 31 2018 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,350,500 | |
Derivative, Swap Type, Average Fixed Price | 25.37 | |
Natural Gas Liquids [Member] | Contract Period January 1 2019 to December 31 2019 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 | |
Natural Gas Liquids [Member] | Contract Period January 1 2020 to December 31 2020 [Member] | Fixed-Price Swap [Member] | ||
Derivative [Line Items] | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 0 | |
Derivative, Swap Type, Average Fixed Price | 0 |
Price and Interest Rate Risk 51
Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized assets | $ 4,122 | |
Gross amounts offset in the consolidated balance sheets | 4,122 | |
Net Amounts Presented in the Consolidated Balance Sheets | 0 | |
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts of recognized liabilities | $ (125) | |
Gross amounts offset in the consolidated balance sheets | 4,122 | |
Net Amounts Presented in the Consolidated Balance Sheets | (12,875) | |
Commodity Contract [Member] | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized assets | 4,122 | |
Gross amounts offset in the consolidated balance sheets | 4,122 | |
Net Amounts Presented in the Consolidated Balance Sheets | 0 | |
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts offset in the consolidated balance sheets | 4,122 | |
Net Amounts Presented in the Consolidated Balance Sheets | (12,875) | |
Interest Rate Contract | ||
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts of recognized liabilities | $ (16,997) | $ (125) |
Price and Interest Rate Risk 52
Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | |||
Derivative asset at beginning of period, net | $ (125) | $ 316,691 | $ 316,691 |
Net premiums and fees received for derivative contracts | 0 | (2,444) | |
Net losses on commodity and interest rate derivative contracts | (12,838) | (43,676) | (46,939) |
Cash settlement received on matured commodity derivative contracts | (7) | (142,476) | (226,876) |
Cash settlements paid on matured interest rate derivative contracts | 95 | $ 4,727 | 13,398 |
Termination of derivative contracts | 0 | (53,955) | |
Derivative asset at end of period, net | $ (12,875) | $ (125) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2017USD ($) | Dec. 31, 2016USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Asset retirement obligations incurred and recorded | $ 299 | $ 713 |
Change in estimate | $ (29) | 1,267 |
Number of Interest Rate Derivatives Held by entity at reporting date | 1 | |
Fair Value Measured on a Recurring Basis | ||
Liabilities: | ||
Commodity derivative contracts | $ (12,875) | |
Interest rate derivative contracts | (125) | |
Total derivative instruments | (12,875) | (125) |
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 2 | ||
Liabilities: | ||
Commodity derivative contracts | (12,875) | |
Interest rate derivative contracts | (125) | |
Total derivative instruments | $ (12,875) | $ (125) |
Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Credit-adjusted risk-free interest rate (in hundredths) | 4.73% | |
Average inflation rate (in hundredths) | 1.77% | |
Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Credit-adjusted risk-free interest rate (in hundredths) | 5.52% | |
Average inflation rate (in hundredths) | 1.97% | |
Senior Notes due 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | $ 11,500 | |
Senior Notes due 2019 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | 3,100 | |
Subordinated Debt due 2023 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | $ 74,300 |
Fair Value Measurements - Unobs
Fair Value Measurements - Unobservable Inputs Reconciliation (Details) - Fair Value Measurements Using Level 3 $ in Thousands | 6 Months Ended |
Jun. 30, 2016USD ($) | |
Unobservable inputs reconciliation | |
Unobservable inputs, beginning of period | $ (5,933) |
Total gains | 6,922 |
Settlements | (3,225) |
Unobservable inputs, end of period | (2,236) |
Change in fair value included in earnings related to derivatives still held as of June 30, | $ 589 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2017 | Dec. 31, 2016 | |
Changes in asset retirement obligations [Abstract] | ||
Asset retirement obligations, beginning of period | $ 272,436 | $ 271,456 |
Liabilities added during the current period | 299 | 713 |
Accretion expense | 5,813 | 12,145 |
Retirements | (946) | (2,230) |
Liabilities related to assets divested | (8,160) | (10,915) |
Change in estimate | (29) | 1,267 |
Asset retirement obligation, end of period | 269,413 | 272,436 |
Less: current obligations | (8,400) | (7,884) |
Long-term asset retirement obligation, end of period | $ 261,013 | $ 264,552 |
Commitments and Contingencies -
Commitments and Contingencies - Transportation Demand Charges (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Feb. 01, 2017 | |
Oil and Gas Delivery Commitments and Contracts | ||
Bankruptcy Claims, Amount of Claims on Material Contracts Rejected (Deprecated 2016-01-31) | $ 24,900 | |
Liabilities subject to compromise, Rejected contracts | $ 20,000 | |
Gross future minimum transportation demand | ||
July 1, 2017 - December 31, 2017 | 760 | |
Due 2,018 | 1,009 | |
Due 2,019 | 820 | |
Due 2,020 | 410 | |
Total | $ 2,999 | |
Minimum | ||
Oil and Gas Delivery Commitments and Contracts | ||
Oil and Gas Delivery Commitments and Contracts, Length of Contract | 4 months | |
Maximum | ||
Oil and Gas Delivery Commitments and Contracts | ||
Oil and Gas Delivery Commitments and Contracts, Length of Contract | 3 years |
Members_ Deficit and Net Loss57
Members’ Deficit and Net Loss per Common and Class B Unit - Preferred Units Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | ||
Liquidation Preference Per Unit | $ 25 | |
Units Outstanding | 13,881,873 | 13,881,873 |
Carrying Value | $ 335,444 | $ 335,444 |
Series A Preferred Units | ||
Class of Stock [Line Items] | ||
Distribution Rate | 7.875% | |
Units Outstanding | 2,581,873 | 2,581,873 |
Carrying Value | $ 62,200 | $ 62,200 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 5,100 | |
Series B Preferred Unit | ||
Class of Stock [Line Items] | ||
Distribution Rate | 7.625% | |
Units Outstanding | 7,000,000 | 7,000,000 |
Carrying Value | $ 169,265 | $ 169,265 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 13,300 | |
Series C Preferred Units | ||
Class of Stock [Line Items] | ||
Distribution Rate | 7.75% | |
Units Outstanding | 4,300,000 | 4,300,000 |
Carrying Value | $ 103,979 | $ 103,979 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 8,300 |
Members_ Deficit and Net Loss58
Members’ Deficit and Net Loss per Common and Class B Unit - Common and Class B Units Rollforward (Details) - Common Units - shares shares in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Members' Equity [Roll Forward] | ||
Beginning of period (shares) | 131,009 | 130,477 |
Partners' Capital Account, Units, Unit-based Compensation net of (Forfeitures) during Period (shares) | (30) | 532 |
End of period (shares) | 130,979 | 131,009 |
Members_ Deficit and Net Loss59
Members’ Deficit and Net Loss per Common and Class B Unit - Net Loss per Common and Class B Unit (Details) - shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Equity [Abstract] | ||||
Antidilutive securities excluded from computation (shares) | 13,472,608 | 2,633,333 | 13,562,608 | 2,633,333 |
Members_ Deficit and Net Loss60
Members’ Deficit and Net Loss per Common and Class B Unit - Distributions Declared (Details) - $ / shares | 1 Months Ended | 6 Months Ended | |
Jan. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2017 | |
Class of Stock [Line Items] | |||
Preferred Unit, Liquidation Preference Per Share (usd per share) | $ 25 | ||
Common Units | |||
Class of Stock [Line Items] | |||
Cash Distributions per Unit (usd per share) | $ 0.03 | $ 0.03 | |
Cash distribution, declaration date | Feb. 18, 2016 | Jan. 20, 2016 | |
Cash Distributions Record Date | Mar. 1, 2016 | Feb. 1, 2016 | |
Cash Distributions Payment Date | Mar. 15, 2016 | Feb. 12, 2016 | |
Series A Preferred Units | |||
Class of Stock [Line Items] | |||
Preferred Unit, Distribution Rate, Percentage | 7.875% | ||
Series B Preferred Unit | |||
Class of Stock [Line Items] | |||
Preferred Unit, Distribution Rate, Percentage | 7.625% | ||
Series C Preferred Units | |||
Class of Stock [Line Items] | |||
Preferred Unit, Distribution Rate, Percentage | 7.75% |
Unit-Based Compensation (Detail
Unit-Based Compensation (Details) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2017USD ($)officershares | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of common unit equivalent per phantom unit issued | shares | 1 | ||||
Amended agreement extension period | 12 months | ||||
Number of annual bonus performance metrics | 4 | ||||
Director | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 1 year | ||||
Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 33.33% | ||||
Phantom Share Units (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 33.33% | ||||
Phantom Share Units (PSUs) | Director | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 480,768 | ||||
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Non-cash compensation | $ 0.9 | $ 1.4 | $ 1.7 | $ 2.6 | |
Selling, General and Administrative Expenses | Phantom Share Units (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Non-cash compensation | 1.6 | 1.2 | $ 3.4 | 2.4 | |
Amended Agreements | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of executives in amended agreements | officer | 3 | ||||
Accrued liability | 1.4 | $ 1.4 | $ 0.4 | ||
Amended Agreements | Executive Officer | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Amended Agreements | Phantom Share Units (PSUs) | Executive Officer | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 10,611,940 | ||||
Amended Agreements | Selling, General and Administrative Expenses | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Non-cash compensation | $ 0.5 | $ 0.7 | $ 1 | $ 1.2 |
Unit-Based Compensation - Summa
Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - Restricted Stock Units (RSUs) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 2.4 | $ 2.4 | ||
Number of Non-vested Units | ||||
Non-vested units at beginning of period (in units) | 647,784 | |||
Forfeited (in units) | (11,958) | |||
Vested (in units) | (257,497) | |||
Non-vested units at end of period (in units) | 378,329 | 378,329 | ||
Weighted Average Grant Date Fair Value | ||||
Non-vested units at beginning of period (in dollars per unit) | $ 19.14 | |||
Forfeited (in dollars per unit) | 17.69 | |||
Vested (in dollars per unit) | 20.80 | |||
Non-vested units at end of period (in dollars per unit) | $ 18.07 | $ 18.07 | ||
Selling, General and Administrative Expenses | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 0.9 | $ 1.4 | $ 1.7 | $ 2.6 |
Unit-Based Compensation - Sum63
Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - Phantom Share Units (PSUs) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 10.7 | $ 10.7 | ||
Unrecognized compensation cost recognition period (in years) | 1 year 7 months | |||
Number of Non-vested Units | ||||
Non-vested units at beginning of period (in units) | 3,628,529 | |||
Granted (in units) | 11,092,708 | |||
Forfeited (in units) | (54,562) | |||
Vested (in units) | (956,830) | |||
Non-vested units at end of period (in units) | 13,709,845 | 13,709,845 | ||
Weighted Average Grant Date Fair Value | ||||
Non-vested units at beginning of period (in dollars per unit) | $ 2.96 | |||
Granted (in dollars per unit) | 0.67 | |||
Forfeited (in dollars per unit) | 2.11 | |||
Vested (in dollars per unit) | 4.31 | |||
Non-vested units at end of period (in dollars per unit) | $ 1.02 | $ 1.02 | ||
Selling, General and Administrative Expenses | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 1.6 | $ 1.2 | $ 3.4 | $ 2.4 |
Shelf Registration Statements (
Shelf Registration Statements (Details) | 6 Months Ended |
Jun. 30, 2017USD ($) | |
Common Units | |
Maximum offering under equity distribution agreement | $ 14,593,606 |