Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Aug. 06, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Vanguard Natural Resources, Inc. | |
Entity Central Index Key | 1,384,072 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Smaller Reporting Company | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 20,100,187 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenues: | ||||
Oil sales | $ 46,503 | $ 92,614 | ||
Natural gas sales | 42,623 | 97,890 | ||
NGLs sales | 22,587 | 44,484 | ||
Oil, natural gas and NGLs sales | 111,713 | 234,988 | ||
Net losses on commodity derivative contracts | (45,332) | (63,917) | ||
Total revenues and losses on commodity derivative contracts | 66,381 | 171,071 | ||
Production: | ||||
Lease operating expenses | 36,763 | 67,758 | ||
Transportation, gathering, processing and compression | 9,768 | 21,270 | ||
Production and other taxes | 7,971 | 17,752 | ||
Depreciation, depletion, amortization, and accretion | 38,711 | 78,750 | ||
Impairment of oil and natural gas properties | 7,552 | 22,153 | ||
Exploration expense | 430 | 1,746 | ||
Selling, general and administrative expenses | 11,108 | 23,844 | ||
Total costs and expenses | 112,303 | 233,273 | ||
Income (loss) from operations | (45,922) | (62,202) | ||
Other income (expense): | ||||
Interest expense | (15,870) | (30,623) | ||
Net gains on interest rate derivative contracts | 0 | 0 | ||
Net gains on divestiture of oil and natural gas properties | 4,900 | 4,900 | ||
Other | (175) | (26) | ||
Total other expense, net | (11,145) | (25,749) | ||
Income (loss) before reorganization items | (57,067) | (87,951) | ||
Reorganization items | (610) | (2,317) | ||
Net loss | (57,677) | (90,268) | ||
Less: Net (income) loss attributable to non-controlling interests | (96) | (189) | ||
Net loss attributable to Vanguard stockholders/unitholders | (57,773) | (90,457) | ||
Distributions to Preferred unitholders | 0 | 0 | ||
Net loss attributable to Common stockholders/ Common and Class B unitholders | $ (57,773) | $ (90,457) | ||
Net loss per share/unit – basic and diluted (usd per share) | $ (2.87) | $ (4.50) | ||
Common Stock | ||||
Weighted average Common shares/units outstanding | ||||
Weighted average Common shares/units outstanding – basic and diluted (in shares) | 20,100 | 20,100 | ||
Class B Units | ||||
Weighted average Common shares/units outstanding | ||||
Weighted average Common shares/units outstanding – basic and diluted (in shares) | 0 | 0 | ||
Predecessor | ||||
Revenues: | ||||
Oil sales | $ 41,046 | $ 85,676 | ||
Natural gas sales | 51,712 | 109,175 | ||
NGLs sales | 14,109 | 30,773 | ||
Oil, natural gas and NGLs sales | 106,867 | 225,624 | ||
Net losses on commodity derivative contracts | (12,875) | (12,868) | ||
Total revenues and losses on commodity derivative contracts | 93,992 | 212,756 | ||
Production: | ||||
Lease operating expenses | 36,823 | 75,305 | ||
Transportation, gathering, processing and compression | 0 | 0 | ||
Production and other taxes | 9,138 | 19,203 | ||
Depreciation, depletion, amortization, and accretion | 25,328 | 51,056 | ||
Impairment of oil and natural gas properties | 0 | 0 | ||
Exploration expense | 0 | 0 | ||
Selling, general and administrative expenses | 9,777 | 20,072 | ||
Total costs and expenses | 81,066 | 165,636 | ||
Income (loss) from operations | 12,926 | 47,120 | ||
Other income (expense): | ||||
Interest expense | (13,832) | (30,273) | ||
Net gains on interest rate derivative contracts | 0 | 30 | ||
Net gains on divestiture of oil and natural gas properties | 0 | 0 | ||
Other | 255 | 311 | ||
Total other expense, net | (13,577) | (29,932) | ||
Income (loss) before reorganization items | (651) | 17,188 | ||
Reorganization items | (53,221) | (79,967) | ||
Net loss | (53,872) | (62,779) | ||
Less: Net (income) loss attributable to non-controlling interests | 5 | (12) | ||
Net loss attributable to Vanguard stockholders/unitholders | (53,867) | (62,791) | ||
Distributions to Preferred unitholders | 0 | (2,230) | ||
Net loss attributable to Common stockholders/ Common and Class B unitholders | $ (53,867) | $ (65,021) | ||
Net loss per share/unit – basic and diluted (usd per share) | $ (0.41) | $ (0.49) | ||
Predecessor | Common Stock | ||||
Weighted average Common shares/units outstanding | ||||
Weighted average Common shares/units outstanding – basic and diluted (in shares) | 130,961 | 130,959 | ||
Predecessor | Class B Units | ||||
Weighted average Common shares/units outstanding | ||||
Weighted average Common shares/units outstanding – basic and diluted (in shares) | 420 | 420 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 7,502 | $ 2,762 |
Trade accounts receivable, net | 53,124 | 67,248 |
Derivative assets | 0 | 2,258 |
Restricted cash | 6,211 | 7,255 |
Prepaid drilling costs | 23,672 | 11,830 |
Assets held for sale | 22,427 | 0 |
Other current assets | 4,126 | 3,934 |
Total current assets | 117,062 | 95,287 |
Oil and natural gas properties | ||
Proved properties | 1,551,261 | 1,560,552 |
Unproved properties | 82,753 | 85,393 |
Oil and natural gas properties, gross - successful effort method | 1,634,014 | 1,645,945 |
Accumulated depreciation, depletion, amortization and impairment | (199,761) | (112,553) |
Oil and natural gas properties, net – successful efforts method | 1,434,253 | 1,533,392 |
Other assets | ||
Derivative assets | 833 | 0 |
Other assets | 9,686 | 14,841 |
Total assets | 1,561,834 | 1,643,520 |
Accounts payable: | ||
Trade | 12,125 | 9,141 |
Accrued liabilities: | ||
Lease operating | 9,942 | 13,560 |
Developmental capital | 6,792 | 12,275 |
Interest | 5,572 | 6,312 |
Production and other taxes | 20,216 | 20,982 |
Other | 13,731 | 9,005 |
Derivative liabilities | 67,202 | 39,212 |
Oil and natural gas revenue payable | 34,296 | 37,422 |
Liabilities held for sale | 978 | 0 |
Other current liabilities | 11,768 | 12,175 |
Total current liabilities | 182,622 | 160,084 |
Long-term debt, net of current portion (Note 5) | 892,569 | 905,976 |
Derivative liabilities | 34,846 | 27,483 |
Asset retirement obligations, net of current portion | 143,335 | 151,717 |
Other long-term liabilities | 554 | 732 |
Total liabilities | 1,253,926 | 1,245,992 |
Commitments and contingencies (Note 9) | ||
Stockholders’ equity/Members’ (deficit) (Note 10) | ||
Successor common stock ($0.001 par value, 50,000,000 shares authorized and 20,100,178 shares issued and outstanding at June 30, 2018 and December 31, 2017) | 20 | 20 |
Successor additional paid-in capital | 507,715 | 506,640 |
Successor accumulated deficit | (201,867) | (111,410) |
Total stockholders' equity | 305,868 | 395,250 |
Non-controlling interest in subsidiary | 2,040 | 2,278 |
Total stockholders' equity attributable to Common stockholders | 307,908 | 397,528 |
Total liabilities and stockholders’ equity | $ 1,561,834 | $ 1,643,520 |
CONDENSED CONSOLIDATED BALANCE4
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (usd per share) | $ 0.001 | $ 0.001 |
Common stock, authorized (shares) | 50,000,000 | 50,000,000 |
Common stock, issued (shares) | 20,100,178 | 20,100,178 |
Common stock, outstanding (shares) | 20,100,178 | 20,100,178 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (SUCCESSOR) (Unaudited) - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Non-controlling Interest |
Beginning balance (shares) at Dec. 31, 2017 | 20,100,178 | 20,100,000 | |||
Beginning balance at Dec. 31, 2017 | $ 397,528 | $ 20 | $ 506,640 | $ (111,410) | $ 2,278 |
Increase (Decrease) in Stockholders' Equity | |||||
Net income (loss) | (90,268) | (90,457) | 189 | ||
Share-based compensation | 1,075 | 1,075 | |||
Potato Hills cash distribution to non-controlling interest | $ (427) | (427) | |||
Ending balance (shares) at Jun. 30, 2018 | 20,100,178 | 20,100,000 | |||
Ending balance at Jun. 30, 2018 | $ 307,908 | $ 20 | $ 507,715 | $ (201,867) | $ 2,040 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 7 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Jul. 31, 2017 | |
Operating activities | ||||
Net loss | $ (90,268) | |||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||
Depreciation, depletion, amortization, and accretion | 78,750 | |||
Impairment of oil and natural gas properties | 22,153 | |||
Amortization of deferred financing costs | 1,361 | |||
Amortization of debt discount | 0 | |||
Non-cash reorganization items | 0 | |||
Compensation related items | 1,075 | |||
Net losses on commodity and interest rate derivative contracts | 63,917 | |||
Cash settlements received (paid) on matured commodity derivative contracts | (27,139) | |||
Cash settlements paid on matured interest rate derivative contracts | 0 | |||
Net gain on divestiture of oil and natural gas properties | (4,900) | |||
Changes in operating assets and liabilities: | ||||
Trade accounts receivable | 14,124 | |||
Other current assets | (1,357) | |||
Net premiums paid on commodity derivative contracts | 0 | |||
Accounts payable and oil and natural gas revenue payable | (136) | |||
Payable to affiliates | 0 | |||
Accrued expenses and other current liabilities | (6,598) | |||
Other assets | 126 | |||
Net cash provided by operating activities | 51,108 | |||
Investing activities | ||||
Additions to property and equipment | (94) | |||
Additions to oil and natural gas properties | (42,637) | |||
Deposits and prepayments of oil and natural gas properties | (49,256) | |||
Proceeds from the sale of oil and natural gas properties | 59,876 | |||
Net cash provided by (used in) investing activities | (32,111) | |||
Financing activities | ||||
Proceeds from long-term debt | 90,000 | |||
Repayment of long-term debt | (104,702) | |||
Repayment of debt under the predecessor revolving credit facility | 0 | |||
Potato Hills distribution to non-controlling interest | (427) | |||
Financing fees | (172) | |||
Net cash used in financing activities | (15,301) | |||
Net increase in cash, cash equivalents and restricted cash | 3,696 | |||
Cash, cash equivalents and restricted cash, beginning of period | 10,017 | |||
Cash, cash equivalents and restricted cash, end of period | 13,713 | |||
Supplemental cash flow information: | ||||
Cash paid for interest | 29,988 | |||
Non-cash investing activity: | ||||
Asset retirement obligations, net | $ 12,294 | |||
Predecessor | ||||
Operating activities | ||||
Net loss | $ (53,872) | $ (62,779) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||
Depreciation, depletion, amortization, and accretion | 25,328 | 51,056 | ||
Impairment of oil and natural gas properties | 0 | 0 | ||
Amortization of deferred financing costs | 2,228 | |||
Amortization of debt discount | 348 | |||
Non-cash reorganization items | 58,755 | |||
Compensation related items | 4,765 | |||
Net losses on commodity and interest rate derivative contracts | 12,838 | |||
Cash settlements received (paid) on matured commodity derivative contracts | 7 | $ 7 | ||
Cash settlements paid on matured interest rate derivative contracts | (95) | (95) | ||
Net gain on divestiture of oil and natural gas properties | 0 | 0 | ||
Changes in operating assets and liabilities: | ||||
Trade accounts receivable | 14,804 | |||
Other current assets | 2,106 | |||
Net premiums paid on commodity derivative contracts | (16) | |||
Accounts payable and oil and natural gas revenue payable | (14,484) | |||
Payable to affiliates | (890) | |||
Accrued expenses and other current liabilities | 5,564 | |||
Other assets | (357) | |||
Net cash provided by operating activities | 73,850 | |||
Investing activities | ||||
Additions to property and equipment | (67) | |||
Additions to oil and natural gas properties | (17,873) | |||
Deposits and prepayments of oil and natural gas properties | (22,330) | |||
Proceeds from the sale of oil and natural gas properties | 107,689 | |||
Net cash provided by (used in) investing activities | 67,419 | |||
Financing activities | ||||
Proceeds from long-term debt | 0 | |||
Repayment of long-term debt | 0 | |||
Repayment of debt under the predecessor revolving credit facility | (22,683) | |||
Potato Hills distribution to non-controlling interest | (235) | |||
Financing fees | (53) | |||
Net cash used in financing activities | (22,971) | |||
Net increase in cash, cash equivalents and restricted cash | 118,298 | |||
Cash, cash equivalents and restricted cash, beginning of period | 49,957 | $ 49,957 | ||
Cash, cash equivalents and restricted cash, end of period | $ 168,255 | 168,255 | ||
Supplemental cash flow information: | ||||
Cash paid for interest | 22,424 | |||
Non-cash investing activity: | ||||
Asset retirement obligations, net | $ 7,890 |
Description of the Business
Description of the Business | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of the Business | Description of the Business We are an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. The Company is currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of June 30, 2018 , we own properties and oil and natural gas reserves primarily located in nine operating areas: • the Green River Basin in Wyoming; • the Piceance Basin in Colorado; • the Permian Basin in West Texas and New Mexico; • the Arkoma Basin in Arkansas and Oklahoma; • the Gulf Coast Basin in Texas, Louisiana and Alabama; • the Big Horn Basin in Wyoming and Montana; • the Anadarko Basin in Oklahoma and North Texas; • the Wind River Basin in Wyoming; and • the Powder River Basin in Wyoming. Following the completion of the financial restructuring on August 1, 2017 (see Note 1, “ Summary of Significant Accounting Policies, (b) Emergence from Voluntary Reorganization under Chapter 11 and (c) Fresh-Start Accounting” ), the Company had 20.1 million shares of its common stock outstanding. The Company’s shares of common stock and warrants are traded and quoted on the OTCQX market (which is operated by OTC Markets Group, Inc.) under the symbol VNRR. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The accompanying condensed consolidated financial statements are unaudited and were prepared from our records. We derived the condensed consolidated balance sheet as of December 31, 2017 from the audited financial statements contained in our 2017 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 along with our 2017 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, 2018 , our significant accounting policies are consistent with those discussed in Note 1 of the Notes to the Consolidated Financial Statements contained in our 2017 Annual Report. (a) Basis of Presentation and Principles of Consolidation The condensed consolidated financial statements as of June 30, 2018 and December 31, 2017 (Successor), and for the three and six months ended June 30, 2018 (Successor) and June 30, 2017 (Predecessor), respectively, include our accounts and those of our subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation. We consolidate Potato Hills Gas Gathering System 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 condensed consolidated financial statements. On June 18, 2018, the Company entered into an agreement to sell our 51% joint venture interest in Potato Hills Gas Gathering System, including the compression assets relating to the gathering system and our working interest in related oil and natural gas producing properties (the “Potato Hills Divestment”). The assets and liabilities associated with the Potato Hills Divestment are classified as “held for sale” on the condensed consolidated balance sheet. Please see Note 4, Divestitures, for further discussion. (b) Emergence from Voluntary Reorganization under Chapter 11 On February 1, 2017 (the “Petition Date”), the Predecessor and certain of its subsidiaries (such subsidiaries, together with the Predecessor, the “Debtors”) filed voluntary petitions for relief 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”). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. On July 18, 2017, the Bankruptcy Court entered an order confirming the Final Plan (as defined in Note 2). The Company emerged from bankruptcy effective August 1, 2017. Please read Note 2, “Emergence From Voluntary Reorganization Under Chapter 11 Proceedings” for a discussion of the Chapter 11 Cases and the Final Plan. (c) Fresh-Start Accounting In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC Topic 852”), we adopted fresh-start accounting as (i) the fair value of the Successor Company’s total assets (the “Reorganization Value”) immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. The Successor evaluated transaction activity between July 31, 2017 and the Effective Date and concluded that an accounting convenience date of July 31, 2017 (the “Convenience Date”) was appropriate for the adoption of fresh-start accounting which resulted in the Successor becoming a new entity for financial reporting purposes as of the Convenience Date. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to July 31, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, July 31, 2017. As such, these periods are not comparable, are labeled Successor or Predecessor, and are separated by a bold black line. (d) Cash, Cash Equivalents and Restricted Cash The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows (in thousands): Successor Predecessor June 30, 2018 December 31, 2017 Cash and cash equivalents $ 7,502 $ 2,762 Restricted cash 6,211 7,255 Total cash, cash equivalents and restricted cash $ 13,713 $ 10,017 (e) Oil and Natural Gas Properties - Transition from Full Cost Method to Successful Efforts Accounting Method Under GAAP, there are two allowed methods of accounting for oil and natural gas properties: the full cost method and the successful efforts method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the calculation of depreciation, depletion and amortization expense (“DD&A”), and the assessment of impairment of oil and natural gas properties. Prior to July 31, 2017, we followed the full cost method of accounting. 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. 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 occurred on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transferred unproved property costs to the amortizable base when unproved properties were evaluated as being impaired and as exploratory wells were 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. Upon emergence from bankruptcy, we elected to adopt the successful efforts method of accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties in the Successor. Under the successful efforts method, we capitalize the costs of acquiring unproved and proved oil and natural gas leasehold acreage. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, and the remaining months in the lease term for the property. Development costs are capitalized, including the costs of unsuccessful and successful development wells and the costs to drill and equip exploratory wells that find proved reserves. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization DD&A of the leasehold and development costs that are capitalized into proved oil and natural gas properties are computed using the units-of-production method, at the district level, based on total proved reserves and proved developed reserves, respectively. Upon sale or retirement of oil and gas properties, the costs and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are assessed for impairment in accordance with ASC Topic 360, Property, Plant and Equipment , when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices, but at least annually. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value. Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and natural gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, future reserve cash flows and the remaining lease term. (f) Income Taxes Prior to July 31, 2017, the Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, in which the taxable income or loss of the Predecessor were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Effective upon consummation of the Final Plan, the Successor became a C corporation subject to federal and state income taxes. As a C corporation, we account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company incurred a net taxable loss in the current taxable period. Thus no current income taxes are anticipated to be paid and no net benefit will be recorded in the Company’s condensed consolidated financial statements due to the full valuation allowance on the tax assets. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). In response, the SEC staff issued Staff Accounting Bulletin 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC Topic 740, “Uncertain Tax Positions” (“ASC Topic 740”). In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC Topic 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. Refer to Note 12, “Income Taxes,” for more information on the Company’s accounting for income taxes. (g) New Pronouncements Recently Adopted In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. Throughout 2015 and 2016, the FASB issued a series of updates to the revenue recognition guidance in ASC Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (ASC Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (“ASC Topic 606”): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. In conjunction with fresh-start accounting, the Company elected to early adopt the standard effective August 1, 2017. We adopted the standard using the modified retrospective method, by which fresh-start accounting allows us to apply the new standard to all new contracts entered into on or after August 1, 2017, and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of August 1, 2017. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3, “Impact of ASC Topic 606,” for further details related to the Company’s adoption of this standard. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (ASC Topic 230): Restricted Cash (“ASU 2016-18”), which is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. ASU 2016-18 was applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company adopted ASU 2016-18 effective January 1, 2018. The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the condensed consolidated statements of cash flows and disclosure reconciling cash and cash equivalents presented on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statements of cash flows. The adoption of this guidance did not have a material impact on the Company’s financial position of results of operations as the impact was primarily related to presentation. (h) New Pronouncements Issued But Not Yet Adopted In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC Topic 842) (“ASU 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (ii) 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. ASU 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be adopted using a modified retrospective approach. We are currently evaluating the provisions of ASU 2016-02 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have allocated resources to the implementation and are in the process of completing contract and lease identification and review. (i) 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 future cash flows, the fair value of derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion expense, income taxes, and non-cash compensation. Actual results could differ from those estimates. (j) 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. |
Emergence from Voluntary Reorga
Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code | 6 Months Ended |
Jun. 30, 2018 | |
Reorganizations [Abstract] | |
Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code | Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code On February 1, 2017, 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 Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.” 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 provided for the reorganization of the Debtors as a going concern and significantly reduced the long-term debt and annual interest payments of the Successor. During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017. The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Predecessor’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 cancelled 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 Successor’s new organizational documents authorize the Successor to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Final Plan on the Effective Date. In addition, on the Effective Date, the Successor entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Successor issued 20.1 million outstanding shares of common stock, $0.001 par value (“Common Stock”). |
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Impact of ASC 606 Adoption | Impact of ASC Topic 606 Adoption In conjunction with the application of fresh-start accounting, we adopted ASC Topic 606, Revenue from Contracts with Customers (“ASC Topic 606”). We adopted using the modified retrospective method, which fresh-start accounting allows us to apply the new standard to all new contracts entered into after August 1, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of July 31, 2017. ASC Topic 606 supersedes previous revenue recognition requirements in ASC Topic 605, Revenue Recognition (“ASC Topic 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The impact of adoption on our current period results is as follows (in thousands): Successor Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) Revenues: Oil sales $ 92,614 $ 92,614 $ — Natural gas sales 97,890 81,910 15,980 NGLs sales 44,484 39,194 5,290 Oil, natural gas and NGLs sales 234,988 213,718 21,270 Net losses on commodity derivative contracts (63,917 ) (63,917 ) — Total revenues and losses on commodity derivative contracts $ 171,071 $ 149,801 $ 21,270 Costs and expenses: Transportation, gathering, processing, and compression $ 21,270 $ — $ 21,270 Net loss $ (90,268 ) $ (90,268 ) $ — Changes to sales of natural gas and NGLs, and transportation, gathering, processing, and compression expense are due to the conclusion that the Company represents the principal and the ultimate third party is our customer in certain natural gas processing and marketing agreements with certain midstream entities in accordance with the control model in ASC Topic 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC Topic 605 where we acted as the agent and the mid-stream processing entity was our customer. As a result, we modified our presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Transportation, gathering, processing and compression expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as Transportation, gathering, processing, and compression expense. Revenue from Contracts with Customers Sales of oil, natural gas and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Natural gas and NGLs Sales Under most of our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether we are the principal or the agent in the transaction. For those contracts where we have concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in our condensed consolidated statement of operations. Alternatively, for those contracts where we have concluded the Company is the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as Transportation, gathering, processing and compression expense in our condensed consolidated statements of operations. Oil sales Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of these third-party transportation fees in our condensed consolidated statements of operations. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC Topic 606, for the three and six months ended June 30, 2018 , there was no material impact to the financial statements due to this change in accounting for our production imbalances. Transaction price allocated to remaining performance obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC Topic 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. For the three and six months ended June 30, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Divestitures and Exchange of Pr
Divestitures and Exchange of Properties | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Divestitures and Exchange of Properties | Divestitures and Exchange of Properties During 2018, the Company completed the sale of certain oil and natural gas properties in the Permian Basin, the Green River Basin and in Mississippi. Net cash proceeds received from the sale of these properties were approximately $59.9 million , subject to customary post-closing adjustments. Additionally, we incurred costs to sell of approximately $1.3 million . These dispositions were treated as asset sales, and resulted in a net gain of approximately $4.9 million which is included in “net gains on divestiture of oil and natural gas properties” on the condensed consolidated statement of operations. The net cash proceeds from these divestments were used to pay down outstanding debt under the Successor Credit Facility (defined in Note 5). In May 2018, the Company completed the trade of its interests in certain properties in the Green River Basin in exchange for interests in other properties within the same basin. The non-cash exchange was accounted for at fair value and no gain or loss was recognized from the exchange. On June 18, 2018, the Company entered into an agreement for the Potato Hills Divestment for a contract price of $22.9 million . The transaction closed on August 1, 2018. The assets and liabilities associated with the Potato Hills Divestment are recorded at cost and classified as “held for sale” on the condensed consolidated balance sheet. At June 30, 2018 , the Company’s condensed consolidated balance sheet included current assets of approximately $22.4 million in “assets held for sale” and current liabilities of approximately $1.0 million in “liabilities held for sale” related to this transaction. The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet (in thousands): Successor June 30, 2018 Assets: Oil and natural gas properties, net $ 18,510 Other property and equipment, net 3,917 Total assets held for sale $ 22,427 Liabilities: Asset retirement obligations $ 932 Other 46 Total liabilities held for sale $ 978 |
Debt
Debt | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our financing arrangements consisted of the following as of the date indicated (in thousands): Successor Description Interest Rate Maturity Date June 30, 2018 December 31, 2017 Successor Credit Facility Variable (1) February 1, 2021 $ 688,500 $ 700,000 Successor Term Loan Variable (2) May 1, 2021 124,063 124,688 Senior Notes due 2024 9.0% February 15, 2024 80,722 80,722 Lease Financing Obligations 4.16% August 10, 2020 (3) 12,861 15,205 Unamortized deferred financing costs (7,449 ) (8,639 ) Total debt $ 898,697 $ 911,976 Less: Current portion of Term Loan (1,250 ) (1,250 ) Current portion of Lease Financing Obligation (4,878 ) (4,750 ) Total long-term debt $ 892,569 $ 905,976 (1) Variable interest rate of 5.80% and 4.90% at June 30, 2018 and December 31, 2017 respectively. (2) Variable interest rate of 9.55% and 8.90% at June 30, 2018 and December 31, 2017 respectively. (3) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. Successor Credit Facility On the Effective Date, VNG, as borrower, entered into the Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A., as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto. Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loan”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date was $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million . The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). On December 21, 2017, the borrowing base was reduced to $825.0 million following the completion of the sale of our properties in the Williston Basin. During June 2018, the borrowing base was further reduced to $765.2 million following the completion of the sale of our properties in the Permian Basin, Gulf Coast Basin and Green River Basin. During the six months ended June 30, 2018 we borrowed $90.0 million under the Successor Credit Facility and made repayments under the Successor Credit Facility and Term Loan of $102.1 million . As discussed in Note 4, “Divestitures,” the $59.9 million of net cash proceeds received from the sale of properties were used to pay down debt. We used borrowings under the Successor Credit Facility to partially pay for capital expenditures incurred in the first half of 2018 and advances to operators for activities to be completed in the second half of 2018. At June 30, 2018 , there were $688.5 million of outstanding borrowings and $76.5 million of borrowing capacity under the Successor Credit Facility, after reflecting a $0.2 million reduction in availability for letters of credit (discussed below). In July 2018, the Company entered into the Second Amendment to the Successor Credit Facility (the “Second Amendment”) among the Company, the Administrative Agent and the lenders party thereto. Among other things, the Second Amendment reduces the borrowing base from $765.2 million to $729.7 million . Further, on August 1, 2018, the borrowing base was reduced to $702.8 million following the completion of the Potato Hills Divestment and the sale of certain properties in the Gulf Coast Basin. Please see Note 13, Subsequent Events for further discussion. The borrowing base under the Successor Credit Facility is subject to adjustments from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the lenders’ petroleum engineers utilizing the lenders’ internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. The next borrowing base redetermination is scheduled for November of 2018. The maturity date of the Successor Credit 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 (i) the alternative base rate plus an applicable margin of 6.50% for an Alternate Base Rate loan or (ii) adjusted 30 -day LIBOR plus an applicable margin of 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 Successor Credit Facility or (ii) adjusted 30 -day LIBOR plus an applicable margin of 2.75% to 3.75% , based on the borrowing base utilization percentage under the Successor Credit Facility. Unused commitments under the Successor Credit 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 Successor Credit Facility). VNG may be required to make mandatory prepayments of the Revolving Loans in connection with certain borrowing base deficiencies or asset divestitures. VNG is required to repay the Term Loans on the last day of each March, June, September and December (commencing with the first full fiscal quarter ended after the Effective Date), in each case, in an amount equal to 0.25% of the original principal amount of such Term Loans and, on the Maturity Date, the remainder of the principal amount of the Term Loans outstanding on such date, together in each case with accrued and unpaid interest on the principal amount to be paid but excluding the date of such payment. The table below shows the amounts of required payments under the Term Loan for each year as of June 30, 2018 (in thousands): Year Required Payments 2018 $ 625 2019 1,250 2020 1,250 2021 through Maturity date 120,938 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 Successor Credit 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 natural gas properties, and pledges of stock of all other direct and indirect subsidiaries of VNG, subject to certain limited exceptions. The Successor Credit 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; 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; anti-corruption laws and sanctions; and security instruments. The Successor Credit 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 Successor Credit 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; requirement to maintain commodity swaps; maintenance of accounts; 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 Successor Credit 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 day 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 calculated as PV-9 of proved reserves, including impact of hedges and strip prices to first lien debt, 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 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 current assets, including any unborrowed capacity on the Successor Credit Facility we are able to draw upon, to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than 1.00 to 1.00. At June 30, 2018, we were in compliance with all of our debt covenants. As previously discussed, we entered into the Second Amendment, which also includes, among others, amendments to certain financial covenants. Please see Note 13, Subsequent Events for further discussion. The Successor Credit 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. Senior Notes due 2024 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 “Senior Notes due 2024”) to certain eligible holders of the Predecessor’s second lien notes (the “Existing Notes”) in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The Senior Notes due 2024 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 obligations under the Senior Notes due 2024 are guaranteed by all of the Company’s subsidiaries (“Second Lien Guarantors”) subject to limited exceptions, and secured on a second-priority basis by substantially all of the Company’s and the Second Lien Guarantors’ assets, including, without limitation, liens on the total value of the Company’s and the Second Lien Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of the Company, subject to certain limited exceptions. The Senior Notes due 2024 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 Company, as Trustee (in such capacity, the “Trustee”) and as Collateral Trustee (in such capacity, the “Collateral Trustee”), which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem the Company’s Common Stock or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from the Company’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2024 achieve an investment grade rating from each of Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., no default or event of default under the Amended and Restated Indenture exists, and the Company delivers to the Trustee an officers’ certificate certifying such events, many of the foregoing covenants will terminate. The Amended and Restated Indenture also contains customary events of default, including (i) default for thirty ( 30 ) days in the payment when due of interest on the Senior Notes due 2024; (ii) default in payment when due of principal of or premium, if any, on the Senior Notes due 2024 at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency with respect to the Company or any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that taken together would constitute a significant subsidiary. If an event of default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes due 2024 may declare all the Senior Notes due 2024 to be due and payable immediately. If an event of default arises from certain events of bankruptcy or insolvency, with respect to the Company, any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that, taken together, would constitute a significant subsidiary, all outstanding Senior Notes due 2024 will become due and payable immediately without further action or notice. Interest is payable on the Senior Notes due 2024 on February 15 and August 15 of each year, beginning on February 15, 2018. The Senior Notes due 2024 will mature on February 15, 2024. At any time prior to February 15, 2020, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Senior Notes due 2024 issued under the Amended and Restated Indenture, with an amount of cash not greater than the net cash proceeds of certain equity offerings, at a redemption price equal to 109% of the principal amount of the Senior Notes due 2024, together with accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% of the aggregate principal amount of the Senior Notes due 2024 originally issued under the Amended and Restated Indenture remain outstanding after such redemption, and (ii) the redemption occurs within one hundred eighty ( 180 ) days of the equity offering. On or after February 15, 2020, the Senior Notes due 2024 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, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below: Year Percentage 2020 106.75 % 2021 104.50 % 2022 102.25 % 2023 and thereafter 100.00 % In addition, at any time prior to February 15, 2020, the Company may on any one or more occasions redeem all or a part of the Senior Notes due 2024 at a redemption price equal to 100% of the principal amount thereof, plus the Applicable Premium (as defined in the Amended and Restated Indenture) as of, and accrued and unpaid interest, if any, to the date of redemption. Letters of Credit At June 30, 2018 , 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 Successor Credit Facility. 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”). The Lease Financing Obligations were confirmed during the bankruptcy process. Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option 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% . |
Price Risk Management Activitie
Price Risk Management Activities | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price Risk Management Activities | Price Risk Management Activities We have entered into derivative contracts primarily with counterparties that are also lenders under our Successor 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. The following tables summarize oil, natural gas, and NGLs commodity derivative contracts in place at June 30, 2018 : Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Gallons Weighted Average July 1, 2018 - December 31, 2018 34,848,000 $ 2.89 1,327,900 $ 46.60 28,593,600 $ 0.60 January 1, 2019 - December 31, 2019 52,539,000 $ 2.79 1,858,200 $ 48.50 16,213,742 $ 0.78 January 1, 2020 - December 31, 2020 47,227,500 $ 2.75 1,393,800 $ 49.53 — $ — Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index July 1, 2018 - December 31, 2018 6,150,000 $ (0.69 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential 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 $ 3.00 575,730 $ 43.81 $ 54.04 January 1, 2020 - December 31, 2020 5,490,000 $ 2.60 $ 3.00 659,340 $ 44.17 $ 55.00 January 1, 2021 - December 31, 2021 1,825,000 $ 2.60 $ 3.07 112,036 $ 47.50 $ 56.05 Balance Sheet Presentation Our commodity derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the condensed 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 condensed consolidated balance sheets for the periods indicated (in thousands): Successor June 30, 2018 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ 8,170 $ (7,337 ) $ 833 Total derivative instruments $ 8,170 $ (7,337 ) $ 833 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ (109,385 ) $ 7,337 $ (102,048 ) Total derivative instruments $ (109,385 ) $ 7,337 $ (102,048 ) Successor December 31, 2017 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ 15,264 $ (13,006 ) $ 2,258 Total derivative instruments $ 15,264 $ (13,006 ) $ 2,258 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ (79,701 ) $ 13,006 $ (66,695 ) Total derivative instruments $ (79,701 ) $ 13,006 $ (66,695 ) 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 Successor Credit Facility (see Note 5 , “Debt” 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 $8.2 million at June 30, 2018 . We minimize the credit risk related to derivative instruments by: (i) entering into derivative instruments with counterparties that are also lenders in our Successor 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 periods indicated are as follows (in thousands): Successor Predecessor Six Months Ended June 30, 2018 Five Months Ended December 31, 2017 Seven Months Ended July 31, 2017 Derivative liability at beginning of period, net $ (64,437 ) $ (24,894 ) $ (125 ) Purchases Net losses on commodity and interest rate derivative contracts (63,917 ) (55,857 ) (24,857 ) Settlements Cash settlements paid (received) on matured commodity derivative contracts 27,139 12,174 (7 ) Cash settlements paid on matured interest rate derivative contracts — — 95 Termination of derivative contracts — 4,140 — Derivative liability at end of period, net $ (101,215 ) $ (64,437 ) $ (24,894 ) |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2018 | |
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. ASC Topic 820 applies to assets and liabilities carried at fair value on the condensed 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 acquisitions of oil and natural gas properties and other intangible assets and the initial measurement of asset retirement obligations. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as 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, including the term loans, represent their approximate fair value because our current borrowing rates are variable and 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, 2018 , the carrying value of our Senior Notes due 2024 approximates its fair value. We consider the inputs to the valuation of our Senior Notes due 2024 to be Level 2. Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swap contracts, and collars. We account for our commodity derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps and basis swap contracts based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option 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. 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): Successor June 30, 2018 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 833 $ 833 Total derivative instruments $ 833 $ 833 Liabilities: Commodity price derivative contracts $ (102,048 ) $ (102,048 ) Total derivative instruments $ (102,048 ) $ (102,048 ) Successor December 31, 2017 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 2,258 $ 2,258 Total derivative instruments $ 2,258 $ 2,258 Liabilities: Commodity price derivative contracts $ (66,695 ) $ (66,695 ) Total derivative instruments $ (66,695 ) $ (66,695 ) 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, some derivative instruments 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 condensed 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. 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 8, “ Asset Retirement Obligations ,” in accordance with ASC Topic 410-20 “ Asset Retirement Obligations. ” 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: (i) estimated plug and abandonment cost per well based on our experience; (ii) estimated remaining life per well based on average reserve life per field; (iii) our credit-adjusted risk-free interest rate; and (iv) the average inflation factor. 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. The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six months ended June 30, 2018 (Successor), we incurred impairment charges of $22.2 million as oil and natural gas properties with a net cost basis of $89.1 million were written down to their fair value of $66.9 million . The write downs primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold and a reduction in the value of certain of our operating districts due to a decline in forward natural gas prices. In order to determine whether the carrying value of an asset is recoverable, the Company compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, the Company writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Upon the Company's emergence from bankruptcy on August 1, 2017, as discussed in Note 1, “Summary of Significant Accounting Policies,” the Company applied fresh-start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at the Convenience Date. The following provides a roll-forward of our asset retirement obligations (in thousands): Asset retirement obligation as of January 1, 2017 (Predecessor) $ 272,436 Liabilities added during the current period 555 Accretion expense 6,795 Retirements (1,161 ) Liabilities related to assets divested (10,107 ) Change in estimate (29 ) Asset retirement obligation at July 31, 2017 (Predecessor) 268,489 Fresh-start adjustment (1) (123,320 ) Asset retirement obligation at July 31, 2017 (Successor) 145,169 Liabilities added during the current period 10,540 Accretion expense 3,975 Liabilities related to assets divested (5,066 ) Retirements (812 ) Change in estimate 3,618 Asset retirement obligation at December 31, 2017 (Successor) 157,424 Liabilities added during the current period 393 Accretion expense 4,827 Liabilities related to assets divested (11,755 ) Liabilities related to assets held for sale (932 ) Retirements (1,448 ) Asset retirement obligation at June 30, 2018 (Successor) 148,509 Less: current obligations (5,174 ) Long-term asset retirement obligation at June 30, 2018 (Successor) $ 143,335 (1) As a result of the application of fresh-start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factor of 1.8% ; and (iv) a credit-adjusted risk-free interest rate of 6.4% . Inputs to the valuation of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability include: (i) estimated plug and abandonment cost per well based on our experience; (ii) estimated remaining life per well based on average reserve life per field; (iii) our credit-adjusted risk-free interest rate and (iv) the average inflation factor. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are sensitive and subject to change. During the five month period ended December 31, 2017 (Successor), we used credit-adjusted risk-free interest rate ranging between 6.2% and 6.4% ; and the average inflation factor of 1.8% . During the six months ended June 30, 2018 , our credit-adjusted risk-free interest rate was 6.5% and the average inflation factor was 1.7% . |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Transportation Demand Charges As of June 30, 2018 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is approximately two 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, 2018 . 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, 2018 (in thousands) July 1, 2018 - December 31, 2018 $ 410 2019 821 2020 410 Total $ 1,641 Lease Commitments Rent expense for our office leases was $1.1 million and $0.9 million for the six months ended June 30, 2018 (Successor) and the six months ended June 30, 2017 (Predecessor), respectively. The rent expense relates to the lease of our office space in Houston, Texas as well as office leases in our other operating areas. As of June 30, 2018 , the minimum contractual obligations were approximately $9.9 million in the aggregate. June 30, 2018 (in thousands) July 1, 2018 - December 31, 2018 $ 668 2019 1,211 2020 1,149 2021 1,170 2022 1,205 Thereafter 4,503 Total $ 9,906 Development Commitments We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. As of June 30, 2018 , total estimated costs to be spent in 2018 are approximately $31.2 million . Legal Proceedings Litigation Relating to Vanguard’s 2015 merger with LRR Energy, L.P. In June and July 2015, purported unitholders of LRR Energy, L.P. (“LRE”) filed four lawsuits challenging Vanguard’s 2015 merger with LRE (the “LRE Merger”). These lawsuits were styled (a) Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware; (b) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; (c) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District; and (d) Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division. These lawsuits have been voluntarily dismissed or nonsuited. On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit in connection with the LRE Merger. This lawsuit is styled Robert Hurwitz v. Eric Mullins et al., Civil Action No. 1:15-cv-00711-MAK, in the United States District Court for the District of Delaware (the “LRE Lawsuit”). On June 22, 2016, the LRE Plaintiff filed his Amended Class Action Complaint (the “Amended LRE Complaint”) against LRE, the members of the board of directors of the general partner of LRE, Vanguard, Lighthouse Merger Sub, LLC, and the members of Vanguard’s board of directors (the “LRE Lawsuit Defendants”). In the Amended LRE Complaint, the LRE Plaintiff alleges multiple causes of action under the Securities Act and Exchange Act related to the registration statement and proxy statement filed with the SEC in connection with the LRE Merger (the “LRE Proxy”). In general, the LRE Plaintiff alleges that the LRE Proxy failed, among other things, to disclose allegedly material details concerning Vanguard’s (x) debt obligations and (y) ability to maintain distributions to unitholders. Based on these allegations, the LRE Plaintiff sought, among other relief, to rescind the LRE Merger, and an award of damages, attorneys’ fees, and costs. On January 2, 2018, the court in the LRE Lawsuit certified a class of plaintiffs that includes all persons or entities holding LRE common units as of August 28, 2015, through the close of the LRE Merger on October 5, 2015, but excluding the LRE Lawsuit Defendants and certain related persons and entities (the “LRE Class”). The window for potential members of the LRE Class to request exclusion from the LRE Class closed on May 29, 2018, with 22 LRE unitholders timely requesting exclusion. On June 27, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff, on his own behalf and on behalf of the LRE Class, entered into a stipulation of settlement (the “Stipulation”). As amended on July 11, 2018, and on July 25, 2018, the Stipulation provides that the LRE Class will settle and release all claims against the LRE Lawsuit Defendants relating to the LRE Merger, in exchange for an aggregate settlement payment of $8.0 million . Of that settlement amount, Vanguard will contribute $0.7 million , with the remainder to be paid by the insurers of the LRE Lawsuit Defendants. The LRE Lawsuit Defendants continue to deny all allegations of liability or wrongdoing. On July 18, 2018, the court held a hearing to consider whether to preliminarily approve the proposed settlement. In response to matters raised at that hearing, on July 25, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff amended the Stipulation and submitted to the court a revised notice of proposed settlement, proof of claim and release form, and summary notice of proposed settlement. On July 26, 2018, the court entered an order preliminarily approving the settlement as set forth in the amended Stipulation. The court has scheduled a hearing to consider final approval of the settlement on December 14, 2018. At that hearing, the court will determine, among other things, whether the proposed settlement is fair and reasonable to the LRE Class and should be approved, thereby forever barring the LRE Class (other than potential members excluded therefrom) from asserting any of the released claims against the LRE Lawsuit Defendants. We are also defendants in certain legal proceedings arising in the normal course of our business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on the Company cannot be predicted with certainty. Furthermore, our insurance may not be adequate to cover all liabilities that may arise out of claims brought against us. If one or more negative outcomes were to occur relative to these matters, the aggregate impact to our financial position, results of operations or cash flow could be material. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under applicable environmental laws, that could have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow. |
Stockholders' Equity
Stockholders' Equity | 6 Months Ended |
Jun. 30, 2018 | |
Equity [Abstract] | |
Stockholders' Equity | Stockholders’ Equity Cancellation of Units and Issuance of Common Stock As previously discussed, all outstanding preferred units issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% (subject to dilution) of outstanding shares of Common Stock and (ii) Preferred Unit Warrants, in full and final satisfaction of their interests. Further, all common equity of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders of the common equity received Common Unit Warrants, in full and final satisfaction of their interests. Please see further discussion below regarding the issuance of new warrants. On the Effective Date, the Company issued 20.1 million shares of Common Stock, $0.001 par value, in accordance with the Final Plan. Warrant Agreement On the Effective Date, the Company entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued: (i) to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), (B) 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and (C) 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with the Series A Preferred Units and Series B Preferred Units, the “Preferred Units”), three and a half year warrants (the “Preferred Unit Warrants”), which will be exercisable to purchase up to 621,649 shares of Common Stock as of the Effective Date; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which will be exercisable to purchase up to 640,876 shares of Common Stock as of the Effective Date. The expiration date of the Warrants is February 1, 2021. The strike price for the Preferred Unit New Warrants is $44.25 , and the strike price for the Common Unit New Warrants is $61.45 . Management Incentive Plan On August 22, 2017, the Company’s board of directors (the “Board”) approved, upon the recommendation of the Company’s Compensation Committee (“Committee”), the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”), which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders. The maximum number of shares of common shares available for issuance under the MIP is 2,233,333 shares. The MIP is administered by the Committee or, in certain instances, its designee. Employees, directors, and consultants of the Company and its subsidiaries are eligible to receive awards of stock options, restricted stock, restricted stock units (“RSUs”) or other stock-based awards at the Committee or its designee's discretion. The Board may amend, modify, suspend, or terminate the MIP in its discretion; however, no amendment, modification, suspension or termination may materially and adversely affect any award previously granted without the consent of the participant or the permitted transferee of the award. No grant will be made under the 2017 Plan more than 10 years after its effective date. Earnings Per Share/Unit Basic earnings per share/unit is computed by dividing net earnings attributable to stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units. The Company uses the treasury stock method to determine the dilutive effect. The diluted earnings per share calculation for each of the three and six months ended June 30, 2018 excluded approximately 1.3 million warrants and 143,181 RSUs that were antidilutive as we were in a loss position. The diluted earnings per unit calculation for the three and six months ended June 30, 2017 excluded approximately 13.5 million and 13.6 million phantom units, respectively, due to their antidilutive effect as we were in a loss position. |
Share-Based Compensation
Share-Based Compensation | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation | Share-Based Compensation Effect of Emergence from Bankruptcy on Unit-Based Compensation Pursuant to the Final Plan, all unvested equity grants under the Predecessor’s Long-Term Incentive Plan (the “Predecessor Incentive Plan”) that were 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 Predecessor’s Incentive Plan was canceled and extinguished, and participants in the Predecessor’s Incentive Plan received no payment or other distribution on account of the Incentive Plan. Management Incentive Plan As discussed in Note 10 , “Stockholders’ Equity,” on August 22, 2017, the Company’s Board approved the MIP, which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders. MIP Restricted Stock Units The MIP allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is expensed over the requisite service period. In January 2018, the Company granted 78,190 time-based restricted stock unit awards to executives and certain management-level employees with a grant-date fair value of $19.50 per unit and a vesting period of three years . Also, in March 2018, a director was granted 5,893 time-based restricted stock unit awards with a grant-date fair value of $11.99 per unit of which 1,474 units vested immediately and the remaining 4,419 units will vest over a period of three years . The following table summarizes our time-based RSUs as of June 30, 2018 : Time-Based Restricted Stock Units Weighted Average Grant Date Fair Value Non-vested at December 31, 2017 7,500 $ 19.50 Granted 84,083 $ 18.97 Vested (1,474 ) $ 11.99 Non-vested at June 30, 2018 90,109 $ 19.13 We expense time-based RSUs on a straight-line basis over the requisite service period. As of June 30, 2018 , the total remaining unearned compensation related to non-vested time-based RSUs was $1.4 million , which will be amortized over the weighted-average remaining service period of 2.4 years. In January 2018, the Company granted total shareholder return (“TSR”) performance restricted stock unit awards to executives and certain management-level employees. A total of 191,390 TSR performance RSUs would vest assuming achievement of the goals at target level. Awards of TSR performance RSUs will be earned based on a predefined performance criteria determined by comparing our total shareholder return during a three -year period to the respective total shareholder returns of companies in a performance peer group. Based upon our ranking in the performance peer group, a recipient of TSR performance RSUs may earn a total award ranging from 0% to 200% of the initial grant. The TSR modifier is considered a market condition. The awards are also subject to certain other performance conditions which were considered in calculating the grant date fair value. We estimate the fair value of TSR Performance RSUs at the grant date using a Monte Carlo simulation. Assumptions used in the Monte Carlo simulation were as follows: 2018 Grant Closing price of our common stock on grant date $19.70 Volatility 42.87% Risk-free interest rate 2.13% Fair value of unit $25.15 We recognize compensation expense on a straight-line basis over the requisite service period. As of June 30, 2018 , total remaining unearned compensation related to TSR performance RSUs was $4.1 million , which will be amortized over the weighted-average remaining service period of 2.5 years. Share-based compensation for the predecessor and successor periods are not comparable. Our condensed consolidated statements of operations reflect non-cash compensation related to our MIP of $0.6 million and $1.1 million for the three and six months ended June 30, 2018 (Successor), respectively, and non-cash compensation related to the Predecessor Incentive Plan of $2.5 million and $5.1 million for the three and six months ended June 30, 2017 (Predecessor), respectively. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes For the six months ended June 30, 2018 , we recorded no income tax expense or benefit. The difference between our effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the six months ended June 30, 2018 , the Company has continued to record a full valuation allowance against its deferred tax position. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets will be realized. On December 22, 2017, President Trump signed into law the Tax Act that significantly reforms the U.S. tax code. Our accounting for the Tax Act is incomplete. However, as noted in our 2017 Annual Report, at December 31, 2017 we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments associated with the reduction of U.S. federal corporate tax rate, changes in net operating loss utilization, and immediate expensing of certain capital investments. We have not made any additional measurement-period adjustments related to these items during the quarter. We are continuing to gather additional information to complete our accounting for these items and expect to complete our accounting within the prescribed measurement period. |
Subsequent Events
Subsequent Events | 6 Months Ended |
Jun. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events Successor Credit Facility On July 5, 2018, the Company entered into the Second Amendment among the Company, the Administrative Agent and the lenders party thereto. Among other things, the Second Amendment reduces the borrowing base from $765.2 million to $729.7 million . The Second Amendment also includes an automatic mechanism to further reduce the borrowing base in connection with dispositions of oil and gas properties (including casualty events), subject to certain exceptions and limitations, and imposes certain conditions on such dispositions. Furthermore, the calculation of EBITDA, as defined under the Second Amendment, among other things, include addbacks in respect of certain exploration expenses, as well as third party fees, costs and expenses in connection with the Plan of Reorganization, also defined in the Second Amendment, together with related severance costs, subject to certain limitations, and the maximum permitted ratio of consolidated first lien debt of VNG and the guarantors under the Successor Credit Facility as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available was revised to the following: 5.25 :1.00 as of the last day of the fiscal quarter ending September 30, 2018; 5.50 :1.00 as of the last day of the fiscal quarter ending December 31, 2018; 5.75 :1.00 as of the last day of the fiscal quarter ending March 31, 2019; 5.25 :1.00 as of the last day of the fiscal quarter ending June 30, 2019; 5.00 :1.00 as of the last day of the fiscal quarter ending September 30, 2019; 4.75 :1.00 as of the last day of the fiscal quarters ending December 31, 2019 and March 31, 2020; 4.50 :1.00 as of the last day of the fiscal quarter ending June 30, 2020; 4.25 :1.00 as of the last day of the fiscal quarter ending September 30, 2020; and 4.00 :1.00 as of the last day of the fiscal quarter ending December 31, 2020 and thereafter. Additionally, the Second Amendment will permit the Company to dispose of certain assets, provided that, following such disposition, the borrowing base is reduced by, and obligations under the Successor Credit Facility are repaid, in each case in the amount of the net proceeds of such disposition. As a result of the dispositions completed in July and August of 2018, as discussed below, the borrowing base was further reduced to $702.8 million . Asset Sales As previously discussed, the Company completed the Potato Hills Divestment on August 1, 2018 for a contract price of $22.9 million . In addition, the Company completed the sale of certain oil and natural gas properties in the Permian and Gulf Coast Basins for a combined gross proceeds of $5.5 million . The net proceeds from the sale of these properties were used to further reduce debt under the Successor Credit Facility. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation The condensed consolidated financial statements as of June 30, 2018 and December 31, 2017 (Successor), and for the three and six months ended June 30, 2018 (Successor) and June 30, 2017 (Predecessor), respectively, include our accounts and those of our subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation. We consolidate Potato Hills Gas Gathering System 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 condensed consolidated financial statements. On June 18, 2018, the Company entered into an agreement to sell our 51% joint venture interest in Potato Hills Gas Gathering System, including the compression assets relating to the gathering system and our working interest in related oil and natural gas producing properties (the “Potato Hills Divestment”). The assets and liabilities associated with the Potato Hills Divestment are classified as “held for sale” on the condensed consolidated balance sheet. Please see Note 4, Divestitures, for further discussion. |
Emergence from Voluntary Reorganization under Chapter 11 | Emergence from Voluntary Reorganization under Chapter 11 On February 1, 2017 (the “Petition Date”), the Predecessor and certain of its subsidiaries (such subsidiaries, together with the Predecessor, the “Debtors”) filed voluntary petitions for relief 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”). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. On July 18, 2017, the Bankruptcy Court entered an order confirming the Final Plan (as defined in Note 2). The Company emerged from bankruptcy effective August 1, 2017. Please read Note 2, “Emergence From Voluntary Reorganization Under Chapter 11 Proceedings” for a discussion of the Chapter 11 Cases and the Final Plan. (c) Fresh-Start Accounting In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC Topic 852”), we adopted fresh-start accounting as (i) the fair value of the Successor Company’s total assets (the “Reorganization Value”) immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. The Successor evaluated transaction activity between July 31, 2017 and the Effective Date and concluded that an accounting convenience date of July 31, 2017 (the “Convenience Date”) was appropriate for the adoption of fresh-start accounting which resulted in the Successor becoming a new entity for financial reporting purposes as of the Convenience Date. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to July 31, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, July 31, 2017. As such, these periods are not comparable, are labeled Successor or Predecessor, and are separated by a bold black line. |
Oil and Natural Gas Properties - Transition from Full Cost Method fo Successful Efforts Accounting Method | Oil and Natural Gas Properties - Transition from Full Cost Method to Successful Efforts Accounting Method Under GAAP, there are two allowed methods of accounting for oil and natural gas properties: the full cost method and the successful efforts method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the calculation of depreciation, depletion and amortization expense (“DD&A”), and the assessment of impairment of oil and natural gas properties. Prior to July 31, 2017, we followed the full cost method of accounting. 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. 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 occurred on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transferred unproved property costs to the amortizable base when unproved properties were evaluated as being impaired and as exploratory wells were 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. Upon emergence from bankruptcy, we elected to adopt the successful efforts method of accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties in the Successor. Under the successful efforts method, we capitalize the costs of acquiring unproved and proved oil and natural gas leasehold acreage. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, and the remaining months in the lease term for the property. Development costs are capitalized, including the costs of unsuccessful and successful development wells and the costs to drill and equip exploratory wells that find proved reserves. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization DD&A of the leasehold and development costs that are capitalized into proved oil and natural gas properties are computed using the units-of-production method, at the district level, based on total proved reserves and proved developed reserves, respectively. Upon sale or retirement of oil and gas properties, the costs and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are assessed for impairment in accordance with ASC Topic 360, Property, Plant and Equipment , when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices, but at least annually. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value. Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and natural gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, future reserve cash flows and the remaining lease term. |
Income Taxes | Income Taxes Prior to July 31, 2017, the Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, in which the taxable income or loss of the Predecessor were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Effective upon consummation of the Final Plan, the Successor became a C corporation subject to federal and state income taxes. As a C corporation, we account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company incurred a net taxable loss in the current taxable period. Thus no current income taxes are anticipated to be paid and no net benefit will be recorded in the Company’s condensed consolidated financial statements due to the full valuation allowance on the tax assets. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). In response, the SEC staff issued Staff Accounting Bulletin 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC Topic 740, “Uncertain Tax Positions” (“ASC Topic 740”). In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC Topic 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. Refer to Note 12, “Income Taxes,” for more information on the Company’s accounting for income taxes. |
New Pronouncements Recently Adopted | New Pronouncements Recently Adopted In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. Throughout 2015 and 2016, the FASB issued a series of updates to the revenue recognition guidance in ASC Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (ASC Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (“ASC Topic 606”): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. In conjunction with fresh-start accounting, the Company elected to early adopt the standard effective August 1, 2017. We adopted the standard using the modified retrospective method, by which fresh-start accounting allows us to apply the new standard to all new contracts entered into on or after August 1, 2017, and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of August 1, 2017. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3, “Impact of ASC Topic 606,” for further details related to the Company’s adoption of this standard. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (ASC Topic 230): Restricted Cash (“ASU 2016-18”), which is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. ASU 2016-18 was applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company adopted ASU 2016-18 effective January 1, 2018. The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the condensed consolidated statements of cash flows and disclosure reconciling cash and cash equivalents presented on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statements of cash flows. The adoption of this guidance did not have a material impact on the Company’s financial position of results of operations as the impact was primarily related to presentation. |
New Pronouncements Issued But Not Yet Adopted | New Pronouncements Issued But Not Yet Adopted In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC Topic 842) (“ASU 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (ii) 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. ASU 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be adopted using a modified retrospective approach. We are currently evaluating the provisions of ASU 2016-02 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have allocated resources to the implementation and are in the process of completing contract and lease identification and review. |
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 future cash flows, the fair value of derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion expense, income taxes, and non-cash compensation. 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 |
Revenue from Contracts with Customers | Revenue from Contracts with Customers Sales of oil, natural gas and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Natural gas and NGLs Sales Under most of our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether we are the principal or the agent in the transaction. For those contracts where we have concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in our condensed consolidated statement of operations. Alternatively, for those contracts where we have concluded the Company is the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as Transportation, gathering, processing and compression expense in our condensed consolidated statements of operations. Oil sales Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of these third-party transportation fees in our condensed consolidated statements of operations. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC Topic 606, for the three and six months ended June 30, 2018 , there was no material impact to the financial statements due to this change in accounting for our production imbalances. Transaction price allocated to remaining performance obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC Topic 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. For the three and six months ended June 30, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Cash, Cash Equivalents, and Restricted Cash | The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows (in thousands): Successor Predecessor June 30, 2018 December 31, 2017 Cash and cash equivalents $ 7,502 $ 2,762 Restricted cash 6,211 7,255 Total cash, cash equivalents and restricted cash $ 13,713 $ 10,017 |
Impact of ASC 606 Adoption (Tab
Impact of ASC 606 Adoption (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Impact of Adoption of ASC 606 on Current Period Results | The impact of adoption on our current period results is as follows (in thousands): Successor Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) Revenues: Oil sales $ 92,614 $ 92,614 $ — Natural gas sales 97,890 81,910 15,980 NGLs sales 44,484 39,194 5,290 Oil, natural gas and NGLs sales 234,988 213,718 21,270 Net losses on commodity derivative contracts (63,917 ) (63,917 ) — Total revenues and losses on commodity derivative contracts $ 171,071 $ 149,801 $ 21,270 Costs and expenses: Transportation, gathering, processing, and compression $ 21,270 $ — $ 21,270 Net loss $ (90,268 ) $ (90,268 ) $ — |
Divestitures and Exchange of 24
Divestitures and Exchange of Properties Divestitures and Exchange of Properties (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Disclosure of Long Lived Assets Held-for-sale | The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet (in thousands): Successor June 30, 2018 Assets: Oil and natural gas properties, net $ 18,510 Other property and equipment, net 3,917 Total assets held for sale $ 22,427 Liabilities: Asset retirement obligations $ 932 Other 46 Total liabilities held for sale $ 978 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Financing Arrangements | Our financing arrangements consisted of the following as of the date indicated (in thousands): Successor Description Interest Rate Maturity Date June 30, 2018 December 31, 2017 Successor Credit Facility Variable (1) February 1, 2021 $ 688,500 $ 700,000 Successor Term Loan Variable (2) May 1, 2021 124,063 124,688 Senior Notes due 2024 9.0% February 15, 2024 80,722 80,722 Lease Financing Obligations 4.16% August 10, 2020 (3) 12,861 15,205 Unamortized deferred financing costs (7,449 ) (8,639 ) Total debt $ 898,697 $ 911,976 Less: Current portion of Term Loan (1,250 ) (1,250 ) Current portion of Lease Financing Obligation (4,878 ) (4,750 ) Total long-term debt $ 892,569 $ 905,976 (1) Variable interest rate of 5.80% and 4.90% at June 30, 2018 and December 31, 2017 respectively. (2) Variable interest rate of 9.55% and 8.90% at June 30, 2018 and December 31, 2017 respectively. (3) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. |
Schedule of Maturities of Long-term Debt | The table below shows the amounts of required payments under the Term Loan for each year as of June 30, 2018 (in thousands): Year Required Payments 2018 $ 625 2019 1,250 2020 1,250 2021 through Maturity date 120,938 |
Schedule of Debt Instrument Redemption | On or after February 15, 2020, the Senior Notes due 2024 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, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below: Year Percentage 2020 106.75 % 2021 104.50 % 2022 102.25 % 2023 and thereafter 100.00 % |
Price Risk Management Activit26
Price Risk Management Activities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Contracts | The following tables summarize oil, natural gas, and NGLs commodity derivative contracts in place at June 30, 2018 : Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Gallons Weighted Average July 1, 2018 - December 31, 2018 34,848,000 $ 2.89 1,327,900 $ 46.60 28,593,600 $ 0.60 January 1, 2019 - December 31, 2019 52,539,000 $ 2.79 1,858,200 $ 48.50 16,213,742 $ 0.78 January 1, 2020 - December 31, 2020 47,227,500 $ 2.75 1,393,800 $ 49.53 — $ — Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index July 1, 2018 - December 31, 2018 6,150,000 $ (0.69 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential 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 $ 3.00 575,730 $ 43.81 $ 54.04 January 1, 2020 - December 31, 2020 5,490,000 $ 2.60 $ 3.00 659,340 $ 44.17 $ 55.00 January 1, 2021 - December 31, 2021 1,825,000 $ 2.60 $ 3.07 112,036 $ 47.50 $ 56.05 |
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 condensed consolidated balance sheets for the periods indicated (in thousands): Successor June 30, 2018 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ 8,170 $ (7,337 ) $ 833 Total derivative instruments $ 8,170 $ (7,337 ) $ 833 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ (109,385 ) $ 7,337 $ (102,048 ) Total derivative instruments $ (109,385 ) $ 7,337 $ (102,048 ) Successor December 31, 2017 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ 15,264 $ (13,006 ) $ 2,258 Total derivative instruments $ 15,264 $ (13,006 ) $ 2,258 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets Commodity price derivative contracts $ (79,701 ) $ 13,006 $ (66,695 ) Total derivative instruments $ (79,701 ) $ 13,006 $ (66,695 ) |
Schedule of Changes in Fair Value of Commodity and Interest Rate Derivatives | Changes in fair value of our commodity and interest rate derivatives for the periods indicated are as follows (in thousands): Successor Predecessor Six Months Ended June 30, 2018 Five Months Ended December 31, 2017 Seven Months Ended July 31, 2017 Derivative liability at beginning of period, net $ (64,437 ) $ (24,894 ) $ (125 ) Purchases Net losses on commodity and interest rate derivative contracts (63,917 ) (55,857 ) (24,857 ) Settlements Cash settlements paid (received) on matured commodity derivative contracts 27,139 12,174 (7 ) Cash settlements paid on matured interest rate derivative contracts — — 95 Termination of derivative contracts — 4,140 — Derivative liability at end of period, net $ (101,215 ) $ (64,437 ) $ (24,894 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis | Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): Successor June 30, 2018 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 833 $ 833 Total derivative instruments $ 833 $ 833 Liabilities: Commodity price derivative contracts $ (102,048 ) $ (102,048 ) Total derivative instruments $ (102,048 ) $ (102,048 ) Successor December 31, 2017 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 2,258 $ 2,258 Total derivative instruments $ 2,258 $ 2,258 Liabilities: Commodity price derivative contracts $ (66,695 ) $ (66,695 ) Total derivative instruments $ (66,695 ) $ (66,695 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Changes in Asset Retirement Obligations | The following provides a roll-forward of our asset retirement obligations (in thousands): Asset retirement obligation as of January 1, 2017 (Predecessor) $ 272,436 Liabilities added during the current period 555 Accretion expense 6,795 Retirements (1,161 ) Liabilities related to assets divested (10,107 ) Change in estimate (29 ) Asset retirement obligation at July 31, 2017 (Predecessor) 268,489 Fresh-start adjustment (1) (123,320 ) Asset retirement obligation at July 31, 2017 (Successor) 145,169 Liabilities added during the current period 10,540 Accretion expense 3,975 Liabilities related to assets divested (5,066 ) Retirements (812 ) Change in estimate 3,618 Asset retirement obligation at December 31, 2017 (Successor) 157,424 Liabilities added during the current period 393 Accretion expense 4,827 Liabilities related to assets divested (11,755 ) Liabilities related to assets held for sale (932 ) Retirements (1,448 ) Asset retirement obligation at June 30, 2018 (Successor) 148,509 Less: current obligations (5,174 ) Long-term asset retirement obligation at June 30, 2018 (Successor) $ 143,335 (1) As a result of the application of fresh-start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factor of 1.8% ; and (iv) a credit-adjusted risk-free interest rate of 6.4% . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of 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, 2018 . 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, 2018 (in thousands) July 1, 2018 - December 31, 2018 $ 410 2019 821 2020 410 Total $ 1,641 |
Schedule of Future Minimum Rental Payments for Operating Leases | As of June 30, 2018 , the minimum contractual obligations were approximately $9.9 million in the aggregate. June 30, 2018 (in thousands) July 1, 2018 - December 31, 2018 $ 668 2019 1,211 2020 1,149 2021 1,170 2022 1,205 Thereafter 4,503 Total $ 9,906 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Nonvested Restricted Stock Units Activity | The following table summarizes our time-based RSUs as of June 30, 2018 : Time-Based Restricted Stock Units Weighted Average Grant Date Fair Value Non-vested at December 31, 2017 7,500 $ 19.50 Granted 84,083 $ 18.97 Vested (1,474 ) $ 11.99 Non-vested at June 30, 2018 90,109 $ 19.13 |
Schedule of Monte Carlo Simulation Assumptions | We estimate the fair value of TSR Performance RSUs at the grant date using a Monte Carlo simulation. Assumptions used in the Monte Carlo simulation were as follows: 2018 Grant Closing price of our common stock on grant date $19.70 Volatility 42.87% Risk-free interest rate 2.13% Fair value of unit $25.15 |
Description of the Business (De
Description of the Business (Details) | 6 Months Ended | ||
Jun. 30, 2018operating_areasshares | Dec. 31, 2017shares | Aug. 01, 2017shares | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Number of operating areas | operating_areas | 9 | ||
Common stock, issued (shares) | shares | 20,100,178 | 20,100,178 | 20,100,000 |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Narrative) (Details) | Jun. 30, 2018 |
Potato Hills Gas Gathering System | |
Ownership Percentage by Parent | 51.00% |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Cash and cash equivalents | $ 7,502 | $ 2,762 |
Restricted cash | 6,211 | 7,255 |
Total cash, cash equivalents and restricted cash | $ 13,713 | $ 10,017 |
Summary of Significant Accoun34
Summary of Significant Accounting Policies (Oil and Natural Gas Properties) (Details) | 7 Months Ended |
Jul. 31, 2017 | |
Predecessor | |
Oil and Natural Gas Properties | |
Discount rate used in determining limitation of capitalized costs | 10.00% |
Emergence from Voluntary Reor35
Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code (Details) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 | Aug. 01, 2017 |
Reorganizations [Abstract] | |||
Common stock (Successor) (shares) | 20,100,178 | 20,100,178 | 20,100,000 |
Common stock, par value (usd per share) | $ 0.001 | $ 0.001 | $ 0.001 |
Impact of ASC 606 Adoption (Det
Impact of ASC 606 Adoption (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2018 | Jun. 30, 2018 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Oil sales | $ 46,503 | $ 92,614 |
Natural gas sales | 42,623 | 97,890 |
NGLs sales | 22,587 | 44,484 |
Oil, natural gas and NGLs sales | 111,713 | 234,988 |
Net losses on commodity derivative contracts | (45,332) | (63,917) |
Total revenues and losses on commodity derivative contracts | 66,381 | 171,071 |
Transportation, gathering, processing and compression | 9,768 | 21,270 |
Net loss | $ (57,677) | (90,268) |
Under ASC 605 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Oil sales | 92,614 | |
Natural gas sales | 81,910 | |
NGLs sales | 39,194 | |
Oil, natural gas and NGLs sales | 213,718 | |
Net losses on commodity derivative contracts | (63,917) | |
Total revenues and losses on commodity derivative contracts | 149,801 | |
Transportation, gathering, processing and compression | 0 | |
Net loss | (90,268) | |
Increase/(Decrease) | ASU 2014-09 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Oil sales | 0 | |
Natural gas sales | 15,980 | |
NGLs sales | 5,290 | |
Oil, natural gas and NGLs sales | 21,270 | |
Net losses on commodity derivative contracts | 0 | |
Total revenues and losses on commodity derivative contracts | 21,270 | |
Transportation, gathering, processing and compression | 21,270 | |
Net loss | $ 0 |
Divestitures and Exchange of 37
Divestitures and Exchange of Properties Divestitures and Exchange of Properties (Details) - USD ($) | Jun. 18, 2018 | Jun. 30, 2018 | Jun. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 |
Business Acquisition [Line Items] | |||||
Net gains on divestiture of oil and natural gas properties, Net of Goodwill Impairment | $ 4,900,000 | $ 4,900,000 | |||
Assets held for sale | $ 22,427,000 | 22,427,000 | 22,427,000 | $ 0 | |
Other 2018 Divestitures [Member] | |||||
Business Acquisition [Line Items] | |||||
Proceeds from Divestiture of Businesses | 59,900,000 | ||||
Transaction costs | 1,300,000 | $ 1,300,000 | 1,300,000 | ||
Net gains on divestiture of oil and natural gas properties, Net of Goodwill Impairment | $ 4,900,000 | ||||
Green River Asset Exchange [Member] | |||||
Business Acquisition [Line Items] | |||||
Net gains on divestiture of oil and natural gas properties, Net of Goodwill Impairment | $ 0 | ||||
Potato Hills Gas Gathering System | |||||
Business Acquisition [Line Items] | |||||
Proceeds from Divestiture of Businesses | $ 22,900,000 |
Divestitures and Exchange of 38
Divestitures and Exchange of Properties Divestitures and Exchange of Properties (Held for Sale) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Assets Held-for-sale, Not Part of Disposal Group [Abstract] | ||
Assets held for sale, oil and natural gas properties | $ 18,510 | |
Assets held for sale, other assets | 3,917 | |
Total assets held for sale | 22,427 | $ 0 |
Liabilities [Abstract] | ||
Liabilities held for sale, asset retirement obligations | 932 | |
Liabilities held for sale, other liabilities | 46 | |
Liabilities held for sale | $ 978 | $ 0 |
Debt (Financing Arrangements) (
Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2018 | Dec. 31, 2017 | Aug. 01, 2017 | |
Debt Instrument [Line Items] | |||
Unamortized deferred financing costs | $ (7,449) | $ (8,639) | |
Total debt | 898,697 | 911,976 | |
Current portion of Term Loan | (1,250) | (1,250) | |
Current portion of Lease Financing Obligation | (4,878) | (4,750) | |
Total long-term debt | $ 892,569 | 905,976 | |
Lease Financing Obligations | |||
Debt Instrument [Line Items] | |||
Stated interest rate (percent) | 4.16% | ||
Maturity Date | Aug. 10, 2020 | ||
Debt Amount Outstanding | $ 12,861 | $ 15,205 | |
Successor Credit Facility | Line of Credit | |||
Debt Instrument [Line Items] | |||
Variable interest rate (percent) | 5.80% | 4.90% | |
Maturity Date | Feb. 1, 2021 | ||
Debt Amount Outstanding | $ 688,500 | $ 700,000 | $ 730,000 |
Successor Term Loan | Term Loan | |||
Debt Instrument [Line Items] | |||
Variable interest rate (percent) | 9.55% | 8.90% | |
Maturity Date | May 1, 2021 | ||
Debt Amount Outstanding | $ 124,063 | $ 124,688 | $ 125,000 |
Senior Notes due 2024 | Senior Notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate (percent) | 9.00% | 9.00% | |
Maturity Date | Feb. 15, 2024 | ||
Debt Amount Outstanding | $ 80,722 | $ 80,722 | $ 80,700 |
Debt (Successor Credit Facility
Debt (Successor Credit Facility Narrative) (Details) $ in Thousands | Aug. 01, 2017USD ($) | Sep. 30, 2020 | Jun. 30, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Feb. 01, 2021 | Mar. 31, 2020 | Dec. 31, 2018 | Jun. 30, 2018USD ($) | Sep. 30, 2019 | Dec. 31, 2018 | Aug. 01, 2018USD ($) | Jul. 05, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 21, 2017USD ($) |
Debt Instrument [Line Items] | ||||||||||||||||||
Repayment of long-term debt | $ 104,702 | |||||||||||||||||
Successor Credit Facility | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Current borrowing capacity | $ 850,000 | 765,200 | $ 825,000 | |||||||||||||||
Repayment of long-term debt | 102,100 | |||||||||||||||||
Remaining borrowing capacity | 76,500 | |||||||||||||||||
Commitment fee (percent) | 0.50% | |||||||||||||||||
Debt covenant, asset coverage ratio | 1.25 | |||||||||||||||||
Debt covenant , current ratio | 1 | |||||||||||||||||
Successor Credit Facility | Subsequent Event | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Current borrowing capacity | $ 702,800 | $ 729,700 | ||||||||||||||||
Successor Credit Facility | Scenario, Forecast [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Debt Instrument, Covenant Ratio, Debt To EBITDA | 4 | 4.75 | 4.25 | 4.50 | ||||||||||||||
Successor Credit Facility | Scenario, Forecast [Member] | Subsequent Event | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Debt Instrument, Covenant Ratio, Debt To EBITDA | 4.25 | 4.50 | 5 | 5.25 | 5.75 | 5.50 | 5.25 | 4 | 4.75 | |||||||||
Successor Credit Facility | Minimum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Liens on oil and gas properties as percentage of total value | 95.00% | |||||||||||||||||
Successor Credit Facility | Maximum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Limit on unrestricted cash and cash equivalents per agreement | $ 35,000 | |||||||||||||||||
Successor Credit Facility | Line of Credit | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Debt amount outstanding | $ 730,000 | 688,500 | $ 700,000 | |||||||||||||||
Letters of credit outstanding | 200 | |||||||||||||||||
Successor Credit Facility | Line of Credit | Base Rate | Minimum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 1.75% | |||||||||||||||||
Successor Credit Facility | Line of Credit | Base Rate | Maximum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 2.75% | |||||||||||||||||
Successor Credit Facility | Line of Credit | 30-day LIBOR | Minimum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 2.75% | |||||||||||||||||
Successor Credit Facility | Line of Credit | 30-day LIBOR | Maximum | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 3.75% | |||||||||||||||||
Successor Term Loan | Term Loan | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Debt amount outstanding | $ 125,000 | $ 124,063 | $ 124,688 | |||||||||||||||
Required quarterly payment principal as percentage of original principal | 0.25% | |||||||||||||||||
Successor Term Loan | Term Loan | Base Rate | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 6.50% | |||||||||||||||||
Successor Term Loan | Term Loan | 30-day LIBOR | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Applicable margin on variable rate (percent) | 7.50% |
Debt (Maturities of Debt) (Deta
Debt (Maturities of Debt) (Details) - Term Loan - Successor Term Loan $ in Thousands | Jun. 30, 2018USD ($) |
Debt Instrument [Line Items] | |
2,018 | $ 625 |
2,019 | 1,250 |
2,020 | 1,250 |
2021 through Maturity date | $ 120,938 |
Debt (Senior Notes due 2024 Nar
Debt (Senior Notes due 2024 Narrative) (Details) - Senior Notes - USD ($) $ in Thousands | Aug. 01, 2017 | Jun. 30, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | |||
Claims from certain eligible holders of Predecessor's second lien notes | $ 80,700 | ||
Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Debt amount outstanding | $ 80,700 | $ 80,722 | $ 80,722 |
Stated interest rate (percent) | 9.00% | 9.00% | |
Number of days overdue on interest payment to trigger default event | 30 days | ||
Percentage of aggregate principal debt representing holders who can declare the debt due immediately upon default | 25.00% | ||
Redemption price subsequent to equity offering (percent) | 100.00% | ||
Senior Notes due 2024 | Redemption period Aug 1, 2017 through Feb 14, 2020 | |||
Debt Instrument [Line Items] | |||
Amount of aggregate principal that may be redeemed | 35.00% | ||
Redemption price (percent) | 109.00% | ||
Required amount of aggregate principal to remain outstanding after redemption | 65.00% | ||
Number of days from equity offering for redemption | 180 days |
Debt (Schedule of Redemption Pr
Debt (Schedule of Redemption Prices) (Details) - Senior Notes - Senior Notes due 2024 | Aug. 01, 2017 |
Twelve-month redemption period beginning Feb 15, 2020 | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 106.75% |
Twelve-month redemption period beginning Feb 15, 2021 | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 104.50% |
Twelve-month redemption period beginning Feb 15, 2022 | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 102.25% |
Debt Instrument, Redemption, Period Five [Member] | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 100.00% |
Debt (Letters of Credit and Lea
Debt (Letters of Credit and Lease Financing Obligations Narrative) (Details) $ in Millions | Jun. 30, 2018USD ($) |
Debt Instrument [Line Items] | |
Aggregate cost of equipment in early buyout option | $ 16 |
Line of Credit | Successor Credit Facility | |
Debt Instrument [Line Items] | |
Letters of credit outstanding | $ 0.2 |
Lease Financing Obligations | |
Debt Instrument [Line Items] | |
Weighted average implicit interest rate (percent) | 4.16% |
Price Risk Management Activit45
Price Risk Management Activities (Commodity Derivatives) (Details) | Jun. 30, 2018MMBTU$ / bbl$ / MMBTU$ / galgalbbl |
Swap [Member] | Contract Period July 1 2018 to Dec 31 2018 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 34,848,000 |
Weighted Average Fixed Price | 2.89 |
Swap [Member] | Contract Period July 1 2018 to Dec 31 2018 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,327,900 |
Weighted Average Fixed Price | $ / bbl | 46.60 |
Swap [Member] | Contract Period July 1 2018 to Dec 31 2018 | NGLs | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | gal | 28,593,600 |
Weighted Average Fixed Price | $ / gal | 0.60 |
Swap [Member] | Contract Period Jan 1 2019 to Dec 31 2019 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 52,539,000 |
Weighted Average Fixed Price | 2.79 |
Swap [Member] | Contract Period Jan 1 2019 to Dec 31 2019 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,858,200 |
Weighted Average Fixed Price | $ / bbl | 48.50 |
Swap [Member] | Contract Period Jan 1 2019 to Dec 31 2019 | NGLs | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | gal | 16,213,742 |
Weighted Average Fixed Price | $ / gal | 0.78 |
Swap [Member] | Contract Period Jan 1 2020 to Dec 31 2020 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 47,227,500 |
Weighted Average Fixed Price | 2.75 |
Swap [Member] | Contract Period Jan 1 2020 to Dec 31 2020 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,393,800 |
Weighted Average Fixed Price | $ / bbl | 49.53 |
Swap [Member] | Contract Period Jan 1 2020 to Dec 31 2020 | NGLs | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | gal | 0 |
Weighted Average Fixed Price | $ / gal | 0 |
Fixed-Price Swaps | Contract Period July 1 2018 to Dec 31 2018 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 6,150,000 |
Weighted Average Fixed Price | 0.69 |
Collars | Contract Period Jan 1 2019 to Dec 31 2019 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 4,125,000 |
Floor Price | 2.60 |
Ceiling Price | 3 |
Collars | Contract Period Jan 1 2019 to Dec 31 2019 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 575,730 |
Floor Price | $ / bbl | 43.81 |
Ceiling Price | $ / bbl | 54.04 |
Collars | Contract Period Jan 1 2020 to Dec 31 2020 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 5,490,000 |
Floor Price | 2.60 |
Ceiling Price | 3 |
Collars | Contract Period Jan 1 2020 to Dec 31 2020 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 659,340 |
Floor Price | $ / bbl | 44.17 |
Ceiling Price | $ / bbl | 55 |
Collars | Contract Period Jan 1 2021 to Dec 31 2021 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 1,825,000 |
Floor Price | 2.60 |
Ceiling Price | 3.07 |
Collars | Contract Period Jan 1 2021 to Dec 31 2021 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 112,036 |
Floor Price | $ / bbl | 47.50 |
Ceiling Price | $ / bbl | 56.05 |
Price Risk Management Activit46
Price Risk Management Activities (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Offsetting Derivative Assets [Abstract] | ||
Gross Amounts of Recognized Assets | $ 8,170 | $ 15,264 |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | (7,337) | (13,006) |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | 833 | 2,258 |
Offsetting Derivative Liabilities [Abstract] | ||
Gross Amounts of Recognized Liabilities | (109,385) | (79,701) |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | 7,337 | 13,006 |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | (102,048) | (66,695) |
Commodity Contract | ||
Offsetting Derivative Assets [Abstract] | ||
Gross Amounts of Recognized Assets | 8,170 | 15,264 |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | (7,337) | (13,006) |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | 833 | 2,258 |
Offsetting Derivative Liabilities [Abstract] | ||
Gross Amounts of Recognized Liabilities | (109,385) | (79,701) |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | 7,337 | 13,006 |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | $ (102,048) | $ (66,695) |
Price Risk Management Activit47
Price Risk Management Activities (Change in Fair Value of Derivatives) (Details) - USD ($) $ in Thousands | 5 Months Ended | 6 Months Ended | 7 Months Ended | |
Dec. 31, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Jul. 31, 2017 | |
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | ||||
Derivative liability at beginning of period, net | $ (24,894) | $ (64,437) | ||
Purchases | ||||
Net losses on commodity and interest rate derivative contracts | (55,857) | (63,917) | ||
Settlements | ||||
Cash settlements paid on matured interest rate derivative contracts | 12,174 | 27,139 | ||
Cash settlements paid on matured interest rate derivative contracts | 0 | 0 | ||
Termination of derivative contracts | 4,140 | 0 | ||
Derivative liability at end of period, net | (64,437) | $ (101,215) | $ (24,894) | |
Predecessor | ||||
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | ||||
Derivative liability at beginning of period, net | $ (24,894) | $ (125) | (125) | |
Purchases | ||||
Net losses on commodity and interest rate derivative contracts | (24,857) | |||
Settlements | ||||
Cash settlements paid on matured interest rate derivative contracts | (7) | (7) | ||
Cash settlements paid on matured interest rate derivative contracts | $ 95 | 95 | ||
Termination of derivative contracts | 0 | |||
Derivative liability at end of period, net | $ (24,894) |
Price Risk Management Activit48
Price Risk Management Activities (Narrative) (Details) $ in Millions | Jun. 30, 2018USD ($) |
Commodity Contract | |
Derivative [Line Items] | |
Estimate of possible loss due to counterparty failure to perform, maximum | $ 8.2 |
Fair Value Measurements (Assets
Fair Value Measurements (Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Commodity price derivative contracts | $ 833 | $ 2,258 |
Total derivative instruments | 833 | 2,258 |
Liabilities: | ||
Commodity price derivative contracts | (102,048) | (66,695) |
Total derivative instruments | (102,048) | (66,695) |
Fair Value Measurements Using Level 2 | ||
Derivative Asset [Abstract] | ||
Commodity price derivative contracts | 833 | 2,258 |
Total derivative instruments | 833 | 2,258 |
Liabilities: | ||
Commodity price derivative contracts | (102,048) | (66,695) |
Total derivative instruments | $ (102,048) | $ (66,695) |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2018USD ($) | Jun. 30, 2018USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Impairment of oil and natural gas properties | $ 7,552 | $ 22,153 |
Properties Subject to Impairment Review | Fair Value Measurements Using Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Oil and natural gas properties, net cost basis | 89,100 | 89,100 |
Oil and natural gas properties, fair value | $ 66,900 | $ 66,900 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | Jul. 31, 2017 | Dec. 31, 2017 | Jun. 30, 2018 | Jul. 31, 2017 |
Roll-forward of asset retirement obligations: | ||||
Asset retirement obligation, beginning balance | $ 145,169 | $ 157,424 | ||
Liabilities added during the current period | 10,540 | 393 | ||
Accretion expense | 3,975 | 4,827 | ||
Retirements | (812) | (1,448) | ||
Liabilities related to assets divested | (5,066) | (11,755) | ||
Liabilities held for sale, asset retirement obligations | (932) | |||
Change in estimate | 3,618 | |||
Fresh-start adjustment | $ (123,320) | |||
Asset retirement obligation, ending balance | $ 145,169 | 157,424 | 148,509 | $ 145,169 |
Less: current obligations | (5,174) | |||
Long-term asset retirement obligation | $ 151,717 | $ 143,335 | ||
Fresh-start accounting valuation, future inflation factor | 1.80% | 1.80% | 1.70% | |
Fresh-start accounting valuation, credit-adjusted risk-free interest rate | 6.40% | 6.50% | ||
Minimum | ||||
Roll-forward of asset retirement obligations: | ||||
Fresh-start accounting valuation, credit-adjusted risk-free interest rate | 6.20% | |||
Maximum | ||||
Roll-forward of asset retirement obligations: | ||||
Fresh-start accounting valuation, credit-adjusted risk-free interest rate | 6.40% | |||
Predecessor | ||||
Roll-forward of asset retirement obligations: | ||||
Asset retirement obligation, beginning balance | $ 268,489 | 272,436 | ||
Liabilities added during the current period | 555 | |||
Accretion expense | 6,795 | |||
Retirements | (1,161) | |||
Liabilities related to assets divested | (10,107) | |||
Change in estimate | (29) | |||
Asset retirement obligation, ending balance | $ 268,489 | $ 268,489 |
Commitments and Contingencies52
Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Gross future minimum transportation demand | |
July 1, 2018 - December 31, 2018 | $ 410 |
Due 2,019 | 821 |
Due 2,020 | 410 |
Total | $ 1,641 |
Maximum | |
Oil and Gas Delivery Commitments and Contracts | |
Remaining term of contracts | 2 years |
Commitments and Contingencies53
Commitments and Contingencies (Lease Commitments) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Future Minimum Payments Obligations | ||
July 1, 2018 - December 31, 2018 | $ 668 | |
2,019 | 1,211 | |
2,020 | 1,149 | |
2,021 | 1,170 | |
2,022 | 1,205 | |
Thereafter | 4,503 | |
Total | 9,906 | |
Predecessor | ||
Rent expense | $ 1,100 | $ 900 |
Commitments and Contingencies54
Commitments and Contingencies (Narrative) (Details) $ in Millions | Jun. 30, 2018USD ($) |
Other Commitments [Line Items] | |
Estimated commitments to third-party operators under joint operating agreements | $ 31.2 |
Estimate of possible loss | 8 |
VNR | |
Other Commitments [Line Items] | |
Estimate of possible loss | $ 0.7 |
Stockholders' Equity (Cancellat
Stockholders' Equity (Cancellation of Units and Issuance of Common Stock) (Details) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 | Aug. 01, 2017 | Jul. 31, 2017 |
Equity [Abstract] | ||||
Percentage of outstanding shares of Common Stock to holders of outstanding Preferred Units immediately prior to the Effective Date | 3.00% | |||
Common stock (Successor) (shares) | 20,100,178 | 20,100,178 | 20,100,000 | |
Common stock, par value (usd per share) | $ 0.001 | $ 0.001 | $ 0.001 |
Stockholders' Equity (Warrant A
Stockholders' Equity (Warrant Agreement) (Details) - $ / shares | Aug. 01, 2017 | Jun. 30, 2018 |
Series A Preferred Units | ||
Class of Warrant or Right [Line Items] | ||
Preferred units, dividend rate (percent) | 7.875% | |
Series B Preferred Unit | ||
Class of Warrant or Right [Line Items] | ||
Preferred units, dividend rate (percent) | 7.625% | |
Series C Preferred Units | ||
Class of Warrant or Right [Line Items] | ||
Preferred units, dividend rate (percent) | 7.75% | |
VNR Preferred Unit New Warrant | ||
Class of Warrant or Right [Line Items] | ||
Number of securities called by warrants (in shares) | 621,649 | |
Warrants, term (in years) | 3 years 6 months | |
Strike price on warrants | $ 44.25 | |
VNR Common Unit New Warrant | ||
Class of Warrant or Right [Line Items] | ||
Number of securities called by warrants (in shares) | 640,876 | |
Warrants, term (in years) | 3 years 6 months | |
Strike price on warrants | $ 61.45 |
Stockholders' Equity (Managemen
Stockholders' Equity (Management Incentive Plan) (Details) - Management Incentive Plan | Aug. 22, 2017shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares available for issuance under the plan (shares) | 2,233,333 |
Number of years from effective date for grant activity under the plan (in years) | 10 years |
Stockholders' Equity (Earning P
Stockholders' Equity (Earning Per Share/Unit) (Details) - shares | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Warrant | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share (shares) | 1,300,000 | ||
Restricted Stock Units (RSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share (shares) | 143,181 | ||
Predecessor | Phantom Share Units (PSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share (shares) | 13,500,000 | 13,600,000 |
Share-Based Compensation (Narra
Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | |||
Jan. 31, 2018 | Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Non-cash compensation | $ 0.6 | $ 1.1 | ||||
Restricted Stock Units (RSUs) | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Granted (in units) | 84,083 | |||||
Weighted average Grant date fair value (in dollars per unit) | $ 18.97 | |||||
Non-vested units (in units) | 90,109 | 90,109 | 7,500 | |||
Unrecognized compensation cost | $ 1.4 | $ 1.4 | ||||
Unrecognized compensation cost recognition period (in years) | 2 years 5 months | |||||
Restricted Stock Units (RSUs) | Management | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Granted (in units) | 78,190 | |||||
Weighted average Grant date fair value (in dollars per unit) | $ 19.50 | |||||
Restricted Stock Units (RSUs) | Management | Vesting Group A | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 3 years | |||||
Restricted Stock Units (RSUs) | Director | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Granted (in units) | 5,893 | |||||
Weighted average Grant date fair value (in dollars per unit) | $ 11.99 | |||||
Restricted Stock Units (RSUs) | Director | Vesting Group A | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Non-vested units (in units) | 4,419 | |||||
Vesting period | 3 years | |||||
Restricted Stock Units (RSUs) | Director | Vesting Group B - Immediate Vesting | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Non-vested units (in units) | 1,474 | |||||
TSR Performance Unit | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation cost | $ 4.1 | $ 4.1 | ||||
Unrecognized compensation cost recognition period (in years) | 2 years 6 months | |||||
TSR Performance Unit | Management | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Granted (in units) | 191,390 | |||||
Term of award (in years) | P3Y | |||||
Minimum | TSR Performance Unit | Management | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Total award as percent of initial grant | 0.00% | |||||
Maximum | TSR Performance Unit | Management | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Total award as percent of initial grant | 200.00% | |||||
Predecessor | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Non-cash compensation | $ 2.5 | $ 5.1 |
Share-Based Compensation (MIP R
Share-Based Compensation (MIP Restricted Stock) (Details) - Restricted Stock Units (RSUs) | 6 Months Ended |
Jun. 30, 2018$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Non-vested units at beginning of period (in units) | shares | 7,500 |
Granted (in units) | shares | 84,083 |
Vested (in units) | shares | (1,474) |
Non-vested units at end of period (in units) | shares | 90,109 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Non-vested units at beginning of period (in dollars per unit) | $ / shares | $ 19.50 |
Granted (in dollars per unit) | $ / shares | 18.97 |
Vested (in dollars per unit) | $ / shares | 11.99 |
Non-vested units at end of period (in dollars per unit) | $ / shares | $ 19.13 |
Share-Based Compensation (Monte
Share-Based Compensation (Monte Carlo Simulation Assumptions) (Details) - Restricted Stock Units (RSUs) | 6 Months Ended |
Jun. 30, 2018$ / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Closing price of our common stock on grant date (in dollars per share) | $ 19.7 |
Volatility (percent) | 42.87% |
Risk-free interest rate (percent) | 2.13% |
Fair value of unit (in dollars per share) | $ 25.1474 |
Subsequent Events (Details)
Subsequent Events (Details) $ in Millions | Aug. 01, 2018USD ($) | Jun. 18, 2018USD ($) | Jun. 30, 2018USD ($) | Sep. 30, 2020 | Jun. 30, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018USD ($) | Sep. 30, 2018 | Feb. 01, 2021 | Mar. 31, 2020 | Dec. 31, 2018 | Sep. 30, 2019 | Dec. 31, 2018 | Jul. 05, 2018USD ($) | Dec. 21, 2017USD ($) | Aug. 01, 2017USD ($) |
Senior Secured Reserve-Based Credit Facility [Member] | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Current borrowing capacity | $ 765.2 | $ 825 | $ 850 | ||||||||||||||||
Senior Secured Reserve-Based Credit Facility [Member] | Subsequent Event | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Current borrowing capacity | $ 702.8 | $ 729.7 | |||||||||||||||||
Scenario, Forecast [Member] | Senior Secured Reserve-Based Credit Facility [Member] | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Debt Instrument, Covenant Ratio, Debt To EBITDA | 4 | 4.75 | 4.25 | 4.50 | |||||||||||||||
Scenario, Forecast [Member] | Senior Secured Reserve-Based Credit Facility [Member] | Subsequent Event | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Debt Instrument, Covenant Ratio, Debt To EBITDA | 4.25 | 4.50 | 5 | 5.25 | 5.75 | 5.50 | 5.25 | 4 | 4.75 | ||||||||||
Potato Hills Gas Gathering System | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 22.9 | ||||||||||||||||||
Potato Hills Gas Gathering System | Subsequent Event | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 22.9 | ||||||||||||||||||
Other 2018 Divestitures [Member] | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 59.9 | ||||||||||||||||||
Other 2018 Divestitures [Member] | Subsequent Event | |||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||
Proceeds from Divestiture of Businesses | $ 5.5 |