Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2019 | May 10, 2019 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Vanguard Natural Resources, Inc. | |
Entity Central Index Key | 0001384072 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Smaller Reporting Company | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2019 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 20,124,080 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Revenues: | ||
Net losses on commodity derivative contracts | $ (61,139) | $ (18,585) |
Total revenues and losses on commodity derivative contracts | 47,971 | 104,690 |
Production: | ||
Lease operating expenses | 26,247 | 30,995 |
Production and other taxes | 9,823 | 9,781 |
Depreciation, depletion, amortization, and accretion | 35,714 | 40,039 |
Impairment of oil and natural gas properties | 438 | 14,601 |
Exploration expense | 201 | 1,316 |
Selling, general and administrative expenses | 12,557 | 12,736 |
Total costs and expenses | 94,502 | 120,970 |
Loss from operations | (46,531) | (16,280) |
Other income (expense): | ||
Interest expense | (16,975) | (14,753) |
Net gains on divestiture of oil and natural gas properties | (458) | 0 |
Other | 87 | 149 |
Total other expense, net | (17,346) | (14,604) |
Loss before reorganization items | (63,877) | (30,884) |
Reorganization items (Note 3) | (18,388) | (1,707) |
Net income (loss) | (82,265) | (32,591) |
Less: Net income attributable to non-controlling interests | 0 | (93) |
Net loss attributable to Common stockholders | $ (82,265) | $ (32,684) |
Net income (loss) per share/unit – basic and diluted (USD per share) | $ (4.09) | $ (1.63) |
Common Stock | ||
Weighted average Common shares/units outstanding | ||
Weighted average Common shares/units outstanding – basic and diluted (in shares) | 20,124 | 20,100 |
Oil sales | ||
Revenues: | ||
Oil, natural gas and NGLs sales | $ 32,748 | $ 46,111 |
Natural gas sales | ||
Revenues: | ||
Oil, natural gas and NGLs sales | 62,314 | 55,267 |
NGLs sales | ||
Revenues: | ||
Oil, natural gas and NGLs sales | 14,048 | 21,897 |
Oil, natural gas and NGLs sales | ||
Revenues: | ||
Oil, natural gas and NGLs sales | 109,110 | 123,275 |
Transportation, gathering, processing, and compression | ||
Production: | ||
Transportation, gathering, processing, and compression | $ 9,522 | $ 11,502 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 5,512 | $ 33,538 |
Trade accounts receivable, net | 55,119 | 62,073 |
Derivative assets | 1,948 | 6,287 |
Restricted cash | 3,750 | 4,450 |
Prepaid drilling costs | 12,519 | 12,476 |
Other current assets | 11,936 | 5,663 |
Total current assets | 90,784 | 124,487 |
Oil and natural gas properties | ||
Proved properties | 1,563,760 | 1,567,903 |
Unproved properties | 81,597 | 81,597 |
Oil and natural gas properties, gross - successful effort method | 1,645,357 | 1,649,500 |
Accumulated depletion, amortization and impairment | (302,521) | (269,972) |
Oil and natural gas properties, net – successful efforts | 1,342,836 | 1,379,528 |
Other assets | ||
Lease assets | 15,503 | |
Derivative assets | 0 | 6,766 |
Other assets | 17,043 | 9,321 |
Total assets | 1,466,166 | 1,520,102 |
Accounts payable: | ||
Trade | 0 | 29,709 |
Accrued liabilities: | ||
Lease operating | 0 | 13,140 |
Developmental capital | 0 | 6,937 |
Interest | 0 | 4,999 |
Production and other taxes | 0 | 23,658 |
Other | 4,426 | 12,175 |
Derivative liabilities | 0 | 6,483 |
Oil and natural gas revenue payable | 0 | 35,802 |
Long-term debt classified as current | 0 | 879,181 |
Other current liabilities | 0 | 9,091 |
Total current liabilities | 4,426 | 1,021,175 |
Long-term debt, net of current portion (Note 6) | 0 | 5,446 |
Asset retirement obligations | 140,615 | 139,433 |
Other long-term liabilities | 0 | 523 |
Total liabilities not subject to compromise | 145,041 | 1,166,577 |
Liabilities subject to compromise (Note 3) | 1,049,274 | 0 |
Total liabilities | 1,194,315 | 1,166,577 |
Commitments and contingencies (Note 11) | ||
Stockholders’ equity/Members’ (deficit) (Note 10) | ||
Common stock ($0.001 par value, 50,000,000 shares authorized; 20,124,080 shares issued and outstanding at March 31, 2019 and December 31, 2018) | 20 | 20 |
Additional paid-in capital | 509,477 | 508,886 |
Accumulated deficit | (237,646) | (155,381) |
Stockholders' Equity Attributable to Parent | 271,851 | 353,525 |
Total liabilities and equity | $ 1,466,166 | $ 1,520,102 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Mar. 31, 2019 | Dec. 31, 2018 |
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) | 20,124,080 | 20,124,080 |
Common stock, outstanding (shares) | 20,124,080 | 20,124,080 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Non-controlling Interest |
Beginning balance (shares) at Dec. 31, 2017 | 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) | (32,591) | (32,684) | 93 | ||
Share-based compensation | 496 | 496 | |||
Potato Hills cash distribution to non-controlling interest | (177) | (177) | |||
Ending balance (shares) at Mar. 31, 2018 | 20,100,000 | ||||
Ending balance at Mar. 31, 2018 | $ 365,256 | $ 20 | 507,136 | (144,094) | $ 2,194 |
Beginning balance (shares) at Dec. 31, 2018 | 20,124,080 | 20,124,000 | |||
Beginning balance at Dec. 31, 2018 | $ 353,525 | $ 20 | 508,886 | (155,381) | |
Increase (Decrease) in Stockholders' Equity | |||||
Net income (loss) | (82,265) | (82,265) | |||
Share-based compensation | $ 591 | 591 | |||
Ending balance (shares) at Mar. 31, 2019 | 20,124,080 | 20,124,000 | |||
Ending balance at Mar. 31, 2019 | $ 271,851 | $ 20 | $ 509,477 | $ (237,646) |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Mar. 31, 2019 | Mar. 31, 2018 | Dec. 31, 2018 | Mar. 31, 2019 | Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | |
Operating activities | |||||||
Net income (loss) | $ (82,265) | $ (32,591) | |||||
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | |||||||
Depreciation, depletion, amortization, and accretion | 35,714 | 40,039 | |||||
Impairment of oil and natural gas properties | 438 | 14,601 | |||||
Amortization of deferred financing costs | 830 | 677 | |||||
Compensation related items | 591 | 496 | |||||
Net losses on commodity derivative contracts | 61,139 | 18,585 | |||||
Cash settlements paid on matured commodity derivative contracts | (16,089) | (9,292) | $ (80,266) | ||||
Net loss on divestiture of oil and natural gas properties | 458 | 0 | |||||
Non-cash reorganization items | 6,311 | 0 | |||||
Changes in operating assets and liabilities: | |||||||
Trade accounts receivable | 6,496 | 13,905 | |||||
Other current assets | (6,359) | (692) | |||||
Accounts payable and oil and natural gas revenue payable | (15,058) | (3,191) | |||||
Accrued expenses and other current liabilities | (729) | (6,292) | |||||
Other assets | (7,807) | 4 | |||||
Net cash provided by (used in) operating activities | (16,330) | 36,249 | |||||
Investing activities | |||||||
Additions to property and equipment | (31) | (68) | |||||
Additions to oil and natural gas properties | (4,012) | (23,270) | |||||
Deposits and prepayments of oil and natural gas properties | (7,033) | (20,777) | |||||
Proceeds from the sale of oil and natural gas properties | 4,461 | 0 | |||||
Net cash used in investing activities | (6,615) | (44,115) | |||||
Financing activities | |||||||
Proceeds from long-term debt | 0 | 48,000 | |||||
Repayment of long-term debt | (5,775) | (34,554) | |||||
Potato Hills distribution to non-controlling interest | 0 | (177) | |||||
Financing fees | (6) | (33) | |||||
Net cash provided by (used in) financing activities | (5,781) | 13,236 | |||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (28,726) | 5,370 | |||||
Cash, cash equivalents and restricted cash, beginning of period | 37,988 | 10,017 | 10,017 | ||||
Cash, cash equivalents and restricted cash, end of period | 9,262 | 15,387 | 37,988 | ||||
Supplemental cash flow information: | |||||||
Cash paid for interest | 8,616 | 16,155 | |||||
Non-cash financing and investing activities: | |||||||
Lease assets obtained in exchange for lease liabilities | 110 | 0 | |||||
Asset retirement obligations, net | 229 | 136 | |||||
Reconciliation of Cash and Cash Equivalents and Restricted Cash | |||||||
Cash and cash equivalents | $ 5,512 | $ 33,538 | $ 9,144 | $ 2,762 | |||
Cash, cash equivalents and restricted cash | $ 37,988 | $ 10,017 | $ 10,017 | 9,262 | 37,988 | 15,387 | 10,017 |
Restricted cash | $ 3,750 | $ 4,450 | $ 6,243 | $ 7,255 |
Description of the Business
Description of the Business | 3 Months Ended |
Mar. 31, 2019 | |
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. We are 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 March 31, 2019 , 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 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. On March 31, 2019 (the “2019 Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “2019 Debtors”) filed voluntary petitions for relief (collectively, the “2019 Bankruptcy Petitions” and, the cases commenced thereby, the “2019 Chapter 11 Cases”) under Chapter 11 of title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The 2019 Chapter 11 Cases are being jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.” See Note 3 for a discussion of the Chapter 11 proceedings. On April 1, 2019, we received notice from the OTC Markets Group Inc. notifying us that, effective April 2, 2019, it was removing the shares of our common stock, par value $0.001 (“Common Stock”), and two series of outstanding warrants from the OTCQX U.S. tier of the OTC Markets and downgrading them to the OTC Pink in light of the 2019 Bankruptcy Petitions. The OTC Pink is a more limited market than the OTCQX U.S. tier, and the quotation of our Common Stock on the OTC Pink may result in a less liquid market available for existing and potential stockholders to trade our Common Stock and could further depress the trading price of our Common Stock. There can be no assurance that any public market for our Common Stock will exist in the future or that the Company or its successor will be able to participate again in the OTCQX U.S. tier. The Company’s shares of common stock and warrants are traded and quoted on the OTC Pink marketplace (the “OTC Pink”) under the symbols VNRRQ, VNRVQ and VNRWQ, respectively. |
Going Concern Assessment
Going Concern Assessment | 3 Months Ended |
Mar. 31, 2019 | |
Reorganizations [Abstract] | |
Going Concern Assessment | Going Concern Assessment The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the 2019 Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. Please see Note 3, “2019 Chapter 11 Proceedings,” for further discussion. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2019 | |
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, 2018 from the audited financial statements contained in our 2018 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 2018 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 March 31, 2019 , our significant accounting policies are consistent with those discussed in Note 1 of the Notes to the Consolidated Financial Statements contained in our 2018 Annual Report. (a) Basis of Presentation and Principles of Consolidation The condensed consolidated financial statements as of March 31, 2019 and December 31, 2018 , and for the three months ended March 31, 2019 and 2018, respectively, include our accounts and those of our subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation. Prior to August 2018, we consolidated the Potato Hills Gas Gathering System as we had 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 August 1, 2018, we completed the sale of 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. For periods subsequent to filing the 2019 Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. (b) Oil and Natural Gas Properties The successful efforts method of accounting is used to account for oil and natural gas properties. 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 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. (c) Income Taxes The Company is 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 March 31, 2019 , 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. (d) New Pronouncements Recently 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 took effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The ASU requires adoption using a modified retrospective transition approach with either (a) periods prior to the adoption date being recast or (b) a cumulative-effect adjustment recognized to the opening balance of retained earnings on the adoption date with prior periods not recast. We adopted ASU No. 2016-02 as of January 1, 2019, using the targeted improvement transition option included in ASU No. 2018-11 - Leases (Topic 842). The targeted improvement approach allows us to apply the standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, we elected the package of practical expedients permitted under the transition guidance within the new standard, which allowed us to carry forward the historical lease classification and not capitalize leases with terms of 12 months or less without a purchase option. In addition, it allowed us not to separate lease and non-lease components. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. The adoption of ASU 2016-02 resulted in the recording of additional net lease assets and lease liabilities of approximately $17.5 million and $18.0 million , respectively, as of January 1, 2019, with the difference largely due to prepaid and deferred rent that were reclassified to the right-of-use (“ROU”) asset value. The standard did not require any adjustment to the opening balance of retained earnings and had no impact on cash flows. Please see Note 10, “Leases,” for further details. In February 2018, the FASB issued ASU No. 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. U.S. GAAP requires deferred tax liabilities and assets to be adjusted for the effect of a change in tax laws or rates, with the effect included in income from continuing operations in the reporting period that includes the enactment date, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income (referred to as “stranded tax effects”). The amendments in this ASU allow a specific exception for reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. In addition, the amendments in this update also require certain disclosures about stranded tax effects. We applied the update beginning January 1, 2019. The adoption of this new guidance had no material impact on our consolidated financial statements. (e) 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 DD&A and accretion expense, income taxes, and non-cash compensation. Actual results could differ from those estimates. (f) 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. |
2019 Chapter 11 Proceedings
2019 Chapter 11 Proceedings | 3 Months Ended |
Mar. 31, 2019 | |
Reorganizations [Abstract] | |
2019 Chapter 11 Proceedings | 2019 Chapter 11 Proceedings Commencement of Bankruptcy Cases On March 31, 2019, the 2019 Debtors filed the 2019 Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court. The 2019 Debtors are being jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.” The subsidiary 2019 Debtors in the 2019 Chapter 11 Cases are VNG, VNRH, VO, EOC, EAC, ERAC, ERUD, ERAP, ERAC II, ERUD II and ERAP II. Reorganization Process We are currently operating our business as a debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We expect to generally continue our operations without interruption during the pendency of the 2019 Chapter 11 Cases. To continue ordinary course operations, we secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the Petition Date were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our prepetition liabilities and obligations should (subject to certain exceptions) be settled or compromised under the Bankruptcy Code through the 2019 Chapter 11 Cases. Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2018 Annual Report on Form 10-K and Part II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q. These include risks and uncertainties arising as a result of the 2019 Chapter 11 Cases, and the number and nature of our outstanding shares and shareholders, assets, liabilities, officers and directors could change materially because of the 2019 Chapter 11 Cases. Creditors’ Committees - Appointment & Formation Official Unsecured Creditors Committee On April 11, 2019, the Office of the United States Trustee appointed the Official Committee of Unsecured Creditors (the “Unsecured Creditors Committee”) pursuant to section 1102 of the Bankruptcy Code. The Unsecured Creditors Committee consists of the following three members: (i) Enterprise Jonah Gas Gathering LLC; (ii) Viva Energy Services LLC; and (iii) Trinity Environmental SWD I, LLC. Exclusivity; Plan of Reorganization Under the Bankruptcy Code, we have the exclusive right to file a plan of reorganization under Chapter 11 through and including July 29, 2019, and to solicit acceptances of such plan through September 27, 2019. We filed a Chapter 11 plan of reorganization, together with an accompanying disclosure statement on April 30, 2019 (as may be amended, modified, or supplemented from time to time, the “2019 Plan”). We plan to emerge from our Chapter 11 cases after we obtain approval from the Bankruptcy Court confirming the 2019 Plan. Among other things, the Plan determines the rights and satisfy the claims of our creditors and security holders. The 2019 Plan is subject to further negotiations with stakeholders and, possibly, decisions by the Bankruptcy Court. Under the absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common stock can receive any distribution or retain any property under a plan of reorganization. The 2019 Plan currently does not contemplate providing any economic recovery to holders of our existing common stock. The ultimate recovery to creditors, if any, will not be determined until confirmation and implementation of the 2019 Plan. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors. Our Plan could result in any of the holders of our liabilities receiving no distribution on account of their interests and cancellation of their holdings. Moreover, the 2019 Plan can be confirmed, under the Bankruptcy Code even though the 2019 Plan provides that the holders of our common stock receive no distribution on account of their equity interests. Schedules and Statements - Claims & Claims Resolution Process To the best of our knowledge, after making reasonable efforts, we have notified all of our known current or potential creditors that the 2019 Debtors have filed Chapter 11 cases. On May 6, 2019 each of the 2019 Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the 2019 Debtors, including executory contracts to which each of the 2019 Debtors is a party, are subject to the qualifications and assumptions included therein, and are subject to amendment or modification as our Chapter 11 cases proceed. The Schedules and Statements may be subject to further amendment or modification after filing. Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wish to assert prepetition claims against us and whose claim (i) is not listed in the Schedules and Statements or (ii) is listed in the Schedules and Statements as disputed, contingent, or unliquidated, must file a proof of claim with the Bankruptcy Court prior to the bar date set by the court. The bar dates are June 14, 2019, for non-governmental creditors, and September 27, 2019, for governmental creditors. As of May 10, 2019, approximately 83 claims totaling $2.3 million have been filed with the Bankruptcy Court against the 2019 Debtors by approximately 73 claimants. We expect additional claims to be filed prior to the bar dates. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We anticipate the claims filed against the 2019 Debtors in the 2019 Chapter 11 Cases will be numerous. We expect the process of resolving claims filed against the 2019 Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with the 2019 Plan. As part of the process, we will work to resolve differences in amounts scheduled by the 2019 Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where necessary. Accordingly, the ultimate number and amount of claims that will be allowed against the 2019 Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated. Plan Support Agreement On May 8, 2019, the 2019 Debtors entered into a Plan Support Agreement (the “Plan Support Agreement”) with (a) certain holders (the “RBL Lenders”) constituting over 66 2/3% in amount and over 50.1% in number of the revolving credit facility claims and over 66 2/3% in amount and over 50.1% in number of those certain secured swap claims, in each case under that certain Fourth Amendment and Restated Credit Agreement, dated as of August 1, 2017, by and among Vanguard Natural Gas, LLC, as borrower, the guarantors party thereto, Citibank N.A., as Administrative Agent, and the other lenders party thereto from time to time (as amended, the “Successor Credit Facility” and the claims thereunder, the “RBL Claims” and “Secured Swap Claims,” as applicable); and (b) certain holders (the “Term Loan Lenders” and, collectively with the RBL Lenders, the “Plan Support Parties”), constituting over 66 2/3% in amount and over 50.1% in number of the term loan claims under the Successor Credit Facility (the “Term Loan Claims”). The Plan Support Agreement sets forth, subject to certain conditions, the commitment of the 2019 Debtors and the Plan Support Parties to support a comprehensive restructuring of the 2019 Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through the 2019 Plan. The Restructuring Transactions will be financed by (i) the issuance of new common stock in the reorganized Company (the “New Common Stock”); (ii) the issuance of a new series of class A preferred stock in the reorganized Company (the “New Preferred Equity Class A Stock”); (iii) potentially the issuance of a new series of class B preferred stock in the reorganized Company (the “New Preferred Equity Class B Stock”); (iv) a new first lien reserve-based revolving credit facility with an initial borrowing base of $65.0 million and a term loan lending facility in the aggregate amount of $65.0 million (the “Exit RBL/Term Loan A Facility”); and (v) a new term loan lending facility in the aggregate amount of $285.0 million (the “Exit Term Loan B Facility,” and together with the Exit RBL/Term Loan A Facility, the “Exit Facilities”). The material terms of the Exit Facilities will be filed in advance of the hearing to consider confirmation of the 2019 Plan. Pursuant to the Plan Support Agreement, the Company intends to commence the solicitation of votes on the 2019 Plan on May 28, 2019, by causing the 2019 Plan and related disclosure statement to be distributed consistent with section 1126(b) of the Bankruptcy Code. Certain principal terms of the 2019 Plan are outlined below: • holders of Allowed DIP Facility Claims (as defined in the 2019 Plan) will receive their pro rata share of participation in the Exit RBL/Term Loan A Facility; • holders of Allowed Revolving Credit Facility Claims and Allowed Secured Swap Claims (each as defined in the 2019 Plan) will receive their pro rata share of and interest in: (i) the Exit Term Loan B Facility; (ii) at least 86.1% of the New Preferred Equity Class A Stock; and (iii) 75% or 89% of the New Common Stock, depending on whether the class of holders of Allowed Senior Note Claims (as defined in the 2019 Plan) votes to accept or reject the 2019 Plan, and subject to dilution on account of the Management Incentive Plan (as defined below) (if any); • holders of Allowed Term Loan Claims will receive a pro rata share and interest in 10% of the New Common Stock, subject to dilution on account of the Management Incentive Plan (if any), as well as at the option of each holder of an Allowed Term Loan Claim, either: (i) such holder’s pro rata share of the New Preferred Equity Class A Stock available to such holders in accordance with the Preferred Equity Documents (as defined in the Plan Support Agreement) (albeit the maximum amount of New Preferred Equity Class A Stock available to all holders of Allowed Term Loan Claims who elect such option shall not exceed 13.9% percent of the New Preferred Equity Class A Stock to be distributed in the aggregate); or (ii) such holder’s pro rata share of the New Preferred Equity Class B Stock; • holders of Allowed Senior Note Claims will receive a pro rata share and interest in: (i) 15% of the New Common Stock, if the class of Allowed Senior Note Claims votes to accept the 2019 Plan, subject to dilution on account of the Management Incentive Plan (if any); or (ii) 1% of the New Common Stock, if the class of Allowed Senior Note Claims votes to reject the 2019 Plan, subject to dilution on account of the Management Incentive Plan (if any); • holders of Allowed General Unsecured Claims (as defined in the Plan Support Agreement) shall receive (to the extent such General Unsecured Claims have not already been paid in full during the 2019 Chapter 11 Cases), in full and final satisfaction, settlement, release, and discharge of, and in exchange for each Allowed General Unsecured Claim, on the Effective Date such treatment as is acceptable to the 2019 Debtors, the Required Consenting Revolver Lenders (as defined in the 2019 Plan), and the DIP Agent (as defined in the 2019 Plan) and in accordance with the Bankruptcy Code, to be determined prior to the hearing to consider approval of the Disclosure Statement; and • the 2019 Plan may provide for the establishment of a customary management incentive plan at the Company to the officers and other key employees of the respective reorganized entities (the “Management Incentive Plan”). The 2019 Plan will provide for releases of specified claims held by the 2019 Debtors, the Plan Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions. The Plan Support Agreement obligates the 2019 Debtors and the Plan Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Plan Support Parties, vote their claims in favor of the 2019 Plan. We believe the Plan Support Agreement will contribute to reducing the duration of the 2019 Chapter 11 Cases. The Plan Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation and consummation of the 2019 Plan, among other requirements, and in the event of certain breaches by the parties under the Plan Support Agreement. Except as otherwise agreed by the 2019 Debtors and the Plan Support Parties, the Plan Support Agreement contemplates the effective date of the Plan will be no later than 120 days after the filing of the 2019 Bankruptcy Petitions, and the Plan Support Agreement will be subject to termination if the effective date of the 2019 Plan has not occurred within that time. There can be no assurances that the Restructuring Transactions will be consummated. See Part II, Item 1A, “Risk Factors” “If the Plan Support Agreement is terminated, our ability to confirm and consummate a Chapter 11 plan of reorganization could be materially and adversely affected.” Debtor-in-Possession Financing In connection with the 2019 Chapter 11 Cases, on the 2019 Petition Date, the 2019 Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, and the DIP Agent. The initial lender under the DIP Credit Agreement is Citibank N.A. The DIP Credit Agreement contains the following terms: • a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019; • a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under the Successor Credit Facility (as defined in Note 6) (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”); • proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court; • the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (c) the occurrence of an event of default (subject to any cure periods), and (d) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases. • interest will accrue at a rate per year equal to the LIBOR rate plus 5.50% , or the adjusted base rate plus 4.50% per annum; • in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the New Money Facility, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid; • the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion; • the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10.0 million , prepayment events, events of default and other provisions; and • generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an Exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date. The relief requested in the DIP Motion was approved by the Bankruptcy Court on April 30, 2019. Acceleration of Debt Obligations As of December 31, 2018, the Company was not in compliance with certain covenants under the Successor Credit Facility (as defined in Note 6). Accordingly, all amounts due under the Successor Credit Facility and New Notes (as defined in Note 6) (collectively, the “Debt Instruments”) are classified as current in the accompanying consolidated balance sheets as of that date. The commencement of the 2019 Chapter 11 Cases is an event of default that accelerated the 2019 Debtors’ obligations under these Debt Instruments as described in further detail below. In addition, as of March 31, 2019, amounts outstanding under the Debt Instruments are included in liabilities subject to compromise in the condensed consolidated balance sheets. Further, in accordance with accounting guidance in ASC 852, we will not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases. • $677.7 million in unpaid principal with respect to the Revolving Loan (defined in Note 6), $123.4 million in unpaid principal with respect to the Term Loan (defined in Note 6), and approximately $11.6 million of interest, fees, and other expenses arising under or in connection with the Successor Credit Facility. • $80.7 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the New Notes issued pursuant to the Amended and Restated Indenture. Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code. Liabilities Subject to Compromise Liabilities subject to compromise represent estimates of known or potential prepetition claims expected to be resolved in connection with the 2019 Chapter 11 Cases. Additional amounts may be included in liabilities subject to compromise in future periods if we elect to reject executory contracts and unexpired leases as part of our 2019 Chapter 11 Cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Quarterly Report on Form 10-Q and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the Chapter 11 process, and we will make adjustments in future periods as necessary and appropriate. Such adjustments may be material. Under the Bankruptcy Code, we may assume, assign or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. If we reject a contract or lease, such rejection generally (1) is treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieves the 2019 Debtors of performing their future obligations under such contract or lease and (3) entitles the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. If we assume an executory contract or unexpired lease, we are generally required to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty. The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of March 31, 2019 : March 31, 2019 (in thousands) Accounts payable $ 17,000 Accrued liabilities 42,507 Undistributed oil and gas revenues 33,453 Derivative liabilities 40,428 Other liabilities 5,425 Debt and accrued interest 894,407 Lease liabilities 16,054 Liabilities subject to compromise $ 1,049,274 Reorganization Items We use this category to reflect, where applicable, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. The following table summarizes the components included in reorganization items on our consolidated statements of operations for three months ended March 31, 2019 : Three Months Ended March 31, 2019 (in thousands) Professional and legal fees (1) $ 12,077 Deferred financing costs and debt discount (2) 6,311 Total Reorganization items $ 18,388 (1) All professional and legal fees were incurred and paid as of March 31, 2019 . (2) Includes a non-cash charge to write off of the unamortized debt issuance costs and debt discounts of $6.3 million related to the Revolving Loan, Term Loan and New Notes as these debt instruments are expected to be impacted by the bankruptcy reorganization process. |
Revenues
Revenues | 3 Months Ended |
Mar. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | Revenues 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. 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 months ended March 31, 2019 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Divestitures
Divestitures | 3 Months Ended |
Mar. 31, 2019 | |
Business Combinations [Abstract] | |
Divestitures | Divestitures During March 2019, the Company completed the sale of certain oil and natural gas properties in the Jonah Field in the Green River Basin. Cash proceeds received from the sale were approximately $4.4 million , subject to customary post-closing adjustments, net of costs to sell of $0.2 million . The net cash proceeds from this divestment were used to pay down outstanding debt under the Successor Credit Facility (defined in Note 6, “Debt” ). |
Debt
Debt | 3 Months Ended |
Mar. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Debt Our financing arrangements consisted of the following as of the date indicated (in thousands): Description Interest Rate Maturity Date March 31, 2019 December 31, 2018 Revolving Loan Variable (1) February 1, 2021 $ 677,718 $ 682,145 Term Loan Variable (2) May 1, 2021 123,438 123,438 New Notes 9.0% February 15, 2024 80,722 80,722 Lease Financing Obligations 4.16% August 10, 2020 (3) — 10,454 Unamortized deferred financing costs — (7,124 ) Total debt $ 881,878 $ 889,635 Less: Liabilities subject to compromise (Note 3) (881,878 ) — Long-term debt classified as current (4) — (879,181 ) Current portion of Lease Financing Obligation (3) — (5,008 ) Total long-term debt $ — $ 5,446 (1) Variable interest rate of 6.53% and 6.27% at March 31, 2019 and December 31, 2018 , respectively. (2) Variable interest rate of 10.28% and 9.96% at March 31, 2019 and December 31, 2018 , respectively. (3) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Assets” line item in the Balance Sheet. See Note 10, “Leases,” for a detailed discussion of our leases. (4) Under ASC Topic 470, “Debt,”, as a result of our debt covenant violations, we classified our debt under our Revolving Loan, Term Loan and New Notes, as current at December 31, 2018 . Acceleration of Debt Obligations As of December 31, 2018, the Company was not in compliance with certain covenants under the Successor Credit Facility (defined herein). Accordingly, all amounts due under the Debt Instruments are classified as current in the accompanying consolidated balance sheets as of that date. The commencement of the 2019 Chapter 11 Cases is an event of default that accelerated the 2019 Debtors’ obligations under these Debt Instruments. As of March 31, 2019, amounts outstanding under the Debt instruments are included in liabilities subject to compromise in the condensed consolidated balance sheets. Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code. Further, in accordance with accounting guidance in ASC 852, we will not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases. Successor Credit Facility Under the Company’s Fourth Amended and Restated Credit Agreement (the “Successor Credit Facility”), the lenders party thereto agreed to provide VNG with an $850.0 million senior secured reserve-based revolving credit facility (the “Revolving Loan”). The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). As of March 31, 2019 , the Successor Credit Facility had a borrowing base of $677.9 million . As discussed in Note 5, “ Divestitures, ” the net cash proceeds received from the sale of properties of $4.4 million were used to pay down debt. At March 31, 2019 , there were $677.7 million of outstanding borrowings under the Successor Credit Facility. 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 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 August 1, 2017), 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 March 31, 2019 (in thousands): Year Required Payments 2019 $ 1,250 2020 $ 1,250 2021 through Maturity date $ 120,938 As discussed above, all amounts due under our Successor Credit Facility are included in liabilities subject to compromise as of March 31, 2019 in the accompanying condensed consolidated balance sheets. 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 and certain customary affirmative and negative covenants. In addition, the Successor Credit Facility also contains certain financial covenants, as amended under the Second Amendment, 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, determined as of the last day of the fiscal quarter ending in the following periods: Period Ratio March 31, 2019 5.75:1.0 June 30, 2019 5.25:1.0 September 30, 2019 5.00:1.0 December 31, 2019 and March 31, 2020 4.75:1.0 June 30, 2020 4.50:1.0 September 30, 2020 4.25:1.0 December 31, 2020 and thereafter 4.00:1.0 ; and (ii) 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 to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than 1.00 to 1.00. 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. 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. New Notes On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes”) 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 obligations under the New Notes 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 New Notes are governed by an Amended and Restated Indenture, dated as of August 1, 2017 (as amended, the “Amended and Restated Indenture”), by and among the Company, certain subsidiary guarantors of the Company (the “Guarantors”) and Delaware Trust Company, as Trustee (in such capacity, the “Trustee”) and as Collateral Trustee (in such capacity, the “Collateral Trustee”), which contains customary affirmative and negative covenants. 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. Interest is payable on the Senior Notes due 2024 on February 15 and August 15 of each year, which began 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. |
Price Risk Management Activitie
Price Risk Management Activities | 3 Months Ended |
Mar. 31, 2019 | |
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. Our derivative contracts with these counterparties are governed by master agreements, which generally specify that a default under any of our debt agreements as well as any bankruptcy filing is an event of default which may result in early termination of such derivative contracts. As a result of our defaults under our debt agreements and our 2019 Bankruptcy Petitions, we were in default under our derivative contracts. In addition, our derivative contract counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the 2019 Debtors as a result of such terminations, in accordance with the terms of the agreements governing such derivative contracts. In April 2019, our derivative contract counterparties unilaterally terminated all derivative contracts to which we were a party and the net settlement owed to counterparties amounted to $53.9 million . 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 March 31, 2019 : Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Gallons Weighted Average April 1, 2019 - December 31, 2019 36,429,000 $ 2.75 1,393,300 $ 48.49 14,666,518 $ 0.91 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 April 1, 2019 - December 31, 2019 11,000,000 $ (0.57 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential April 1, 2019 - December 31, 2019 4,125,000 $ (0.25 ) Enable East Gas and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index April 1, 2019 - December 31, 2019 343,750 $ (5.78 ) WTI Midland and WTI Cushing Basis Differential January 1, 2020 - December 31, 2020 366,000 $ (0.10 ) WTI Midland and WTI Cushing Basis Differential April 1, 2019 - December 31, 2019 137,500 $ (20.40 ) WTI and WCS Basis Differential Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) April 1, 2019 - December 31, 2019 4,125,000 $ 2.60 $ 3.00 424,370 $ 43.78 $ 54.03 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 $ 3.07 294,536 $ 55.25 $ 63.76 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): March 31, 2019 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 $ 7,758 $ (5,810 ) $ 1,948 Total derivative instruments $ 7,758 $ (5,810 ) $ 1,948 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 (1) Commodity price derivative contracts $ (46,238 ) $ 5,810 $ (40,428 ) Total derivative instruments $ (46,238 ) $ 5,810 $ (40,428 ) (1) Included in liabilities subject to compromise in the accompanying condensed consolidated balance sheets as of March 31, 2019. December 31, 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 $ 22,361 $ (9,308 ) $ 13,053 Total derivative instruments $ 22,361 $ (9,308 ) $ 13,053 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 $ (15,791 ) $ 9,308 $ (6,483 ) Total derivative instruments $ (15,791 ) $ 9,308 $ (6,483 ) 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. As previously discussed, all of our counterparties were participants in our Successor Credit Facility (see Note 6 , “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 $7.8 million at March 31, 2019 . 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 derivatives for the periods indicated are as follows (in thousands): Three Months Ended March 31, 2019 Year Ended December 31, 2018 Derivative asset (liability) at beginning of period, net $ 6,570 $ (64,437 ) Purchases Net losses on commodity and interest rate derivative contracts (61,139 ) (9,259 ) Settlements Cash settlements paid on matured commodity derivative contracts 16,089 80,266 Derivative asset (liability) at end of period, net $ (38,480 ) $ 6,570 |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): March 31, 2019 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 1,948 $ 1,948 Total derivative instruments $ 1,948 $ 1,948 Liabilities: Commodity price derivative contracts $ (40,428 ) $ (40,428 ) Total derivative instruments $ (40,428 ) $ (40,428 ) December 31, 2018 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 13,053 $ 13,053 Total derivative instruments $ 13,053 $ 13,053 Liabilities: Commodity price derivative contracts $ (6,483 ) $ (6,483 ) Total derivative instruments $ (6,483 ) $ (6,483 ) 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. 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 three months ended March 31, 2019 , we incurred impairment charges of $0.4 million as oil and natural gas properties with a net cost basis of $1.1 million were written down to their fair value of $0.7 million . During the three months ended March 31, 2018 , we incurred impairment charges of $14.6 million as oil and natural gas properties with a net cost basis of $73.0 million were written down to their fair value of $58.4 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 | 3 Months Ended |
Mar. 31, 2019 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The following provides a roll-forward of our asset retirement obligations (in thousands): Asset retirement obligation at January 1, 2018 $ 157,424 Liabilities added during the current period 610 Accretion expense 9,295 Liabilities related to assets divested (16,687 ) Retirements (2,499 ) Change in estimate (4,935 ) Asset retirement obligation at December 31, 2018 143,208 Liabilities added during the current period 65 Accretion expense 2,180 Liabilities related to assets divested (294 ) Retirements (118 ) Asset retirement obligation at March 31, 2019 145,041 Less: current obligations (4,426 ) Long-term asset retirement obligation at March 31, 2019 $ 140,615 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 year ended December 31, 2018, we used credit-adjusted risk-free interest rate ranging between 6.5% and 7.1% ; and the average inflation factor of 1.7% . During the three months ended March 31, 2019 , our credit-adjusted risk-free interest rate was 6.8% and the average inflation factor was 1.6% . |
Leases
Leases | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Leases | Leases We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets and, as result of the 2019 Chapter 11 Cases, the lease liabilities are included in liabilities subject to compromise on our consolidated balance sheets. Operating leases with lease term of 12 months or less are not capitalized and excluded from operating lease ROU assets. The lease payments are expensed on a straight-line basis over the term of the lease. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. We do not have any variable lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. We lease certain real estate, well equipment, vehicles, and information technology equipment. For certain well equipment, real-estate, and vehicle leases we account for the lease and non-lease components as a single lease component, although generally these may be accounted for separately if deemed significant. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 10 years or more. The exercise of lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. The components of lease expense for the three months ended March 31, 2019 were as follows (in thousands): Three Months Ended Lease Expense Classification March 31, 2019 Assets Short-term lease cost Selling, general and administrative expenses or Lease operating expenses 295 Operating lease cost Selling, general and administrative expenses or Lease operating expenses 851 Finance lease cost Amortization of lease assets Depreciation, depletion, amortization and accretion 1,333 Interest on lease liabilities Interest expense 137 Net lease cost $ 2,616 Information regarding our lease terms and discount rates as of March 31, 2019 were as follows: March 31, 2019 Weighted-average remaining lease term (years) Operating leases 5.7 Finance leases 1.9 Weighted-average discount rate Operating leases 18.6 % Finance leases 5.5 % Supplemental balance sheet information related to leases as of March 31, 2019 was as follows: Leases (in thousands) Classification March 31, 2019 Assets Operating lease assets Lease assets $ 6,272 Finance lease assets, at cost Lease assets 10,564 Accumulated amortization Lease assets (1,333 ) Finance lease assets, net Lease assets 9,231 Total lease assets $ 15,503 Liabilities Current Operating Liabilities subject to compromise $ 1,466 Finance Liabilities subject to compromise 5,099 Long-Term Operating Liabilities subject to compromise 5,255 Finance Liabilities subject to compromise 4,234 Total lease liabilities $ 16,054 The maturity of our lease liabilities as of March 31, 2019 were as follows (in thousands): Operating Leases Finance Leases Total 2019 (remaining of year) $ 2,059 $ 4,113 $ 6,172 2020 1,772 4,400 6,172 2021 1,563 1,320 2,883 2022 1,255 30 1,285 2023 1,247 — 1,247 Thereafter 3,150 — 3,150 Total undiscounted lease liability 11,046 9,863 20,909 Imputed interest (4,325 ) (530 ) (4,855 ) Total discounted liability $ 6,721 $ 9,333 $ 16,054 Supplemental cash flow and other information related to leases for the three months ended March 31, 2019 was as follows (in thousands): Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,045 Operating cash flows from finance leases $ 137 Financing cash flows from finance leases $ 1,231 Rent expense for our office leases was $0.5 million for the three months ended March 31, 2018. The rent expense was for the lease of our office space in Houston, Texas as well as office leases in our other operating areas. Prior to the adoption of ASU No. 2016-02, our policy was to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease. |
Leases | Leases We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets and, as result of the 2019 Chapter 11 Cases, the lease liabilities are included in liabilities subject to compromise on our consolidated balance sheets. Operating leases with lease term of 12 months or less are not capitalized and excluded from operating lease ROU assets. The lease payments are expensed on a straight-line basis over the term of the lease. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. We do not have any variable lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. We lease certain real estate, well equipment, vehicles, and information technology equipment. For certain well equipment, real-estate, and vehicle leases we account for the lease and non-lease components as a single lease component, although generally these may be accounted for separately if deemed significant. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 10 years or more. The exercise of lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. The components of lease expense for the three months ended March 31, 2019 were as follows (in thousands): Three Months Ended Lease Expense Classification March 31, 2019 Assets Short-term lease cost Selling, general and administrative expenses or Lease operating expenses 295 Operating lease cost Selling, general and administrative expenses or Lease operating expenses 851 Finance lease cost Amortization of lease assets Depreciation, depletion, amortization and accretion 1,333 Interest on lease liabilities Interest expense 137 Net lease cost $ 2,616 Information regarding our lease terms and discount rates as of March 31, 2019 were as follows: March 31, 2019 Weighted-average remaining lease term (years) Operating leases 5.7 Finance leases 1.9 Weighted-average discount rate Operating leases 18.6 % Finance leases 5.5 % Supplemental balance sheet information related to leases as of March 31, 2019 was as follows: Leases (in thousands) Classification March 31, 2019 Assets Operating lease assets Lease assets $ 6,272 Finance lease assets, at cost Lease assets 10,564 Accumulated amortization Lease assets (1,333 ) Finance lease assets, net Lease assets 9,231 Total lease assets $ 15,503 Liabilities Current Operating Liabilities subject to compromise $ 1,466 Finance Liabilities subject to compromise 5,099 Long-Term Operating Liabilities subject to compromise 5,255 Finance Liabilities subject to compromise 4,234 Total lease liabilities $ 16,054 The maturity of our lease liabilities as of March 31, 2019 were as follows (in thousands): Operating Leases Finance Leases Total 2019 (remaining of year) $ 2,059 $ 4,113 $ 6,172 2020 1,772 4,400 6,172 2021 1,563 1,320 2,883 2022 1,255 30 1,285 2023 1,247 — 1,247 Thereafter 3,150 — 3,150 Total undiscounted lease liability 11,046 9,863 20,909 Imputed interest (4,325 ) (530 ) (4,855 ) Total discounted liability $ 6,721 $ 9,333 $ 16,054 Supplemental cash flow and other information related to leases for the three months ended March 31, 2019 was as follows (in thousands): Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,045 Operating cash flows from finance leases $ 137 Financing cash flows from finance leases $ 1,231 Rent expense for our office leases was $0.5 million for the three months ended March 31, 2018. The rent expense was for the lease of our office space in Houston, Texas as well as office leases in our other operating areas. Prior to the adoption of ASU No. 2016-02, our policy was to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Lease Commitments As of December 31, 2018, the minimum contractual obligations under our lease commitments were approximately $9.2 million in the aggregate. Please see Note 10, “Leases,” for a detailed discussion of our current accounting for leases with the adoption of ASU 2016-02. Lease Payments (in thousands) 2019 $ 1,211 2020 1,149 2021 1,169 2022 1,204 2023 1,241 Thereafter 3,262 Total $ 9,236 Transportation Demand Charges As of March 31, 2019 , we have a contract that provides firm transportation capacity on pipeline systems. The remaining term on this contract is approximately one year and requires 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 March 31, 2019 . 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. March 31, 2019 (in thousands) April 1, 2019 - December 31, 2019 615 2020 410 Total $ 1,025 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 March 31, 2019 , total estimated costs to be spent in 20 19 is approximately $12.0 million , of which $5.0 million relates to our drilling and completion commitments in the Pinedale field in the Green River Basin. Legal Proceedings We are 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 reasonably be expected to have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow. Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed, subject to reinstatement when either the Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 3, “2019 Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases. |
Stockholders' Equity
Stockholders' Equity | 3 Months Ended |
Mar. 31, 2019 | |
Equity [Abstract] | |
Stockholders' Equity | Stockholders’ Equity Warrant Agreement On August 1, 2017, 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 are exercisable to purchase up to 621,649 shares of Common Stock; 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 are exercisable to purchase up to 640,876 shares of Common Stock. 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 . As set forth above, the 2019 Plan does not contemplate providing a recovery to any holders of current equity, including the Warrants. Earnings Per Share/Unit Basic earnings per share/unit is computed by dividing net earnings attributable to stockholders 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. The Company uses the treasury stock method to determine the dilutive effect. The diluted earnings per share calculation for the three months ended March 31, 2019 and 2018 excluded 301,065 RSUs and 173,629 RSUs, respectively, and approximately 1.3 million warrants for each of the period, that were antidilutive as we were in a loss position. |
Share-Based Compensation
Share-Based Compensation | 3 Months Ended |
Mar. 31, 2019 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation | Share-Based Compensation The following table summarizes our time-based RSUs as of March 31, 2019 : Time-Based Restricted Stock Units Weighted Average Grant Date Fair Value Non-vested at December 31, 2018 244,496 $ 16.62 Vested (1,473 ) $ 11.99 Non-vested at March 31, 2019 243,023 $ 16.65 We expense time-based RSUs on a straight-line basis over the requisite service period. As of March 31, 2019 , the total remaining unearned compensation related to non-vested time-based RSUs was $3.1 million , which will be amortized over the weighted-average remaining service period of 1.7 years. The 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 estimated the fair value of TSR Performance RSUs at the modification date using a Monte Carlo simulation. Assumptions used in the Monte Carlo simulation were as follows: TSR Performance RSU Replacement Awards Modification date September 11, 2018 Remaining performance period 2.31 years VNR closing price $5.40 VNR beginning TSR price $19.00 Compounded risk-free interest rate (2.31-yr) 2.75% VNR historical volatility (2.31-yr) 71.69% Fair value of unit $19.76 We recognize compensation expense on a straight-line basis over the requisite service period. As of March 31, 2019 , total remaining unearned compensation related to TSR performance RSUs was $1.0 million , which will be amortized over the weighted-average remaining service period of 1.8 years. Our condensed consolidated statements of operations reflect non-cash compensation related to our MIP of $0.6 million and $0.5 million for the three months ended March 31, 2019 and 2018 , respectively. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes For the three months ended March 31, 2019 , 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 three months ended March 31, 2019 , 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. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2019 | |
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 March 31, 2019 and December 31, 2018 , and for the three months ended March 31, 2019 and 2018, respectively, include our accounts and those of our subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation. Prior to August 2018, we consolidated the Potato Hills Gas Gathering System as we had 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 August 1, 2018, we completed the sale of 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. For periods subsequent to filing the 2019 Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The successful efforts method of accounting is used to account for oil and natural gas properties. 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 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 The Company is 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 March 31, 2019 , 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. |
New Pronouncements Recently Adopted | New Pronouncements Recently 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 took effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The ASU requires adoption using a modified retrospective transition approach with either (a) periods prior to the adoption date being recast or (b) a cumulative-effect adjustment recognized to the opening balance of retained earnings on the adoption date with prior periods not recast. We adopted ASU No. 2016-02 as of January 1, 2019, using the targeted improvement transition option included in ASU No. 2018-11 - Leases (Topic 842). The targeted improvement approach allows us to apply the standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, we elected the package of practical expedients permitted under the transition guidance within the new standard, which allowed us to carry forward the historical lease classification and not capitalize leases with terms of 12 months or less without a purchase option. In addition, it allowed us not to separate lease and non-lease components. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. The adoption of ASU 2016-02 resulted in the recording of additional net lease assets and lease liabilities of approximately $17.5 million and $18.0 million , respectively, as of January 1, 2019, with the difference largely due to prepaid and deferred rent that were reclassified to the right-of-use (“ROU”) asset value. The standard did not require any adjustment to the opening balance of retained earnings and had no impact on cash flows. Please see Note 10, “Leases,” for further details. In February 2018, the FASB issued ASU No. 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. U.S. GAAP requires deferred tax liabilities and assets to be adjusted for the effect of a change in tax laws or rates, with the effect included in income from continuing operations in the reporting period that includes the enactment date, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income (referred to as “stranded tax effects”). The amendments in this ASU allow a specific exception for reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. In addition, the amendments in this update also require certain disclosures about stranded tax effects. We applied the update beginning January 1, 2019. The adoption of this new guidance had no material impact on our consolidated financial statements. |
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 DD&A 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 Recognition | 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. 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 months ended March 31, 2019 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
2019 Chapter 11 Proceedings (Ta
2019 Chapter 11 Proceedings (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Reorganizations [Abstract] | |
Schedule of Liabilities Subject to compromise | The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of March 31, 2019 : March 31, 2019 (in thousands) Accounts payable $ 17,000 Accrued liabilities 42,507 Undistributed oil and gas revenues 33,453 Derivative liabilities 40,428 Other liabilities 5,425 Debt and accrued interest 894,407 Lease liabilities 16,054 Liabilities subject to compromise $ 1,049,274 |
Schedule of Reorganization Items | The following table summarizes the components included in reorganization items on our consolidated statements of operations for three months ended March 31, 2019 : Three Months Ended March 31, 2019 (in thousands) Professional and legal fees (1) $ 12,077 Deferred financing costs and debt discount (2) 6,311 Total Reorganization items $ 18,388 (1) All professional and legal fees were incurred and paid as of March 31, 2019 . (2) Includes a non-cash charge to write off of the unamortized debt issuance costs and debt discounts of $6.3 million related to the Revolving Loan, Term Loan and New Notes as these debt instruments are expected to be impacted by the bankruptcy reorganization process. |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of Financing Arrangements | Our financing arrangements consisted of the following as of the date indicated (in thousands): Description Interest Rate Maturity Date March 31, 2019 December 31, 2018 Revolving Loan Variable (1) February 1, 2021 $ 677,718 $ 682,145 Term Loan Variable (2) May 1, 2021 123,438 123,438 New Notes 9.0% February 15, 2024 80,722 80,722 Lease Financing Obligations 4.16% August 10, 2020 (3) — 10,454 Unamortized deferred financing costs — (7,124 ) Total debt $ 881,878 $ 889,635 Less: Liabilities subject to compromise (Note 3) (881,878 ) — Long-term debt classified as current (4) — (879,181 ) Current portion of Lease Financing Obligation (3) — (5,008 ) Total long-term debt $ — $ 5,446 (1) Variable interest rate of 6.53% and 6.27% at March 31, 2019 and December 31, 2018 , respectively. (2) Variable interest rate of 10.28% and 9.96% at March 31, 2019 and December 31, 2018 , respectively. (3) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Assets” line item in the Balance Sheet. See Note 10, “Leases,” for a detailed discussion of our leases. (4) Under ASC Topic 470, “Debt,”, as a result of our debt covenant violations, we classified our debt under our Revolving Loan, Term Loan and New Notes, as current at December 31, 2018 . |
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 March 31, 2019 (in thousands): Year Required Payments 2019 $ 1,250 2020 $ 1,250 2021 through Maturity date $ 120,938 |
Schedule of Financial Debt Covenant Ratio | 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, determined as of the last day of the fiscal quarter ending in the following periods: Period Ratio March 31, 2019 5.75:1.0 June 30, 2019 5.25:1.0 September 30, 2019 5.00:1.0 December 31, 2019 and March 31, 2020 4.75:1.0 June 30, 2020 4.50:1.0 September 30, 2020 4.25:1.0 December 31, 2020 and thereafter 4.00:1.0 |
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 Activit_2
Price Risk Management Activities (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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 March 31, 2019 : Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Gallons Weighted Average April 1, 2019 - December 31, 2019 36,429,000 $ 2.75 1,393,300 $ 48.49 14,666,518 $ 0.91 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 April 1, 2019 - December 31, 2019 11,000,000 $ (0.57 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential April 1, 2019 - December 31, 2019 4,125,000 $ (0.25 ) Enable East Gas and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index April 1, 2019 - December 31, 2019 343,750 $ (5.78 ) WTI Midland and WTI Cushing Basis Differential January 1, 2020 - December 31, 2020 366,000 $ (0.10 ) WTI Midland and WTI Cushing Basis Differential April 1, 2019 - December 31, 2019 137,500 $ (20.40 ) WTI and WCS Basis Differential Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) April 1, 2019 - December 31, 2019 4,125,000 $ 2.60 $ 3.00 424,370 $ 43.78 $ 54.03 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 $ 3.07 294,536 $ 55.25 $ 63.76 |
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): March 31, 2019 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 $ 7,758 $ (5,810 ) $ 1,948 Total derivative instruments $ 7,758 $ (5,810 ) $ 1,948 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 (1) Commodity price derivative contracts $ (46,238 ) $ 5,810 $ (40,428 ) Total derivative instruments $ (46,238 ) $ 5,810 $ (40,428 ) (1) Included in liabilities subject to compromise in the accompanying condensed consolidated balance sheets as of March 31, 2019. December 31, 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 $ 22,361 $ (9,308 ) $ 13,053 Total derivative instruments $ 22,361 $ (9,308 ) $ 13,053 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 $ (15,791 ) $ 9,308 $ (6,483 ) Total derivative instruments $ (15,791 ) $ 9,308 $ (6,483 ) |
Schedule of Changes in Fair Value of Commodity and Interest Rate Derivatives | Changes in fair value of our commodity derivatives for the periods indicated are as follows (in thousands): Three Months Ended March 31, 2019 Year Ended December 31, 2018 Derivative asset (liability) at beginning of period, net $ 6,570 $ (64,437 ) Purchases Net losses on commodity and interest rate derivative contracts (61,139 ) (9,259 ) Settlements Cash settlements paid on matured commodity derivative contracts 16,089 80,266 Derivative asset (liability) at end of period, net $ (38,480 ) $ 6,570 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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): March 31, 2019 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 1,948 $ 1,948 Total derivative instruments $ 1,948 $ 1,948 Liabilities: Commodity price derivative contracts $ (40,428 ) $ (40,428 ) Total derivative instruments $ (40,428 ) $ (40,428 ) December 31, 2018 Fair Value Measurements Assets/Liabilities Using Level 2 at Fair Value Assets: Commodity price derivative contracts $ 13,053 $ 13,053 Total derivative instruments $ 13,053 $ 13,053 Liabilities: Commodity price derivative contracts $ (6,483 ) $ (6,483 ) Total derivative instruments $ (6,483 ) $ (6,483 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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 at January 1, 2018 $ 157,424 Liabilities added during the current period 610 Accretion expense 9,295 Liabilities related to assets divested (16,687 ) Retirements (2,499 ) Change in estimate (4,935 ) Asset retirement obligation at December 31, 2018 143,208 Liabilities added during the current period 65 Accretion expense 2,180 Liabilities related to assets divested (294 ) Retirements (118 ) Asset retirement obligation at March 31, 2019 145,041 Less: current obligations (4,426 ) Long-term asset retirement obligation at March 31, 2019 $ 140,615 |
Leases (Tables)
Leases (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Leases | Supplemental cash flow and other information related to leases for the three months ended March 31, 2019 was as follows (in thousands): Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,045 Operating cash flows from finance leases $ 137 Financing cash flows from finance leases $ 1,231 The components of lease expense for the three months ended March 31, 2019 were as follows (in thousands): Three Months Ended Lease Expense Classification March 31, 2019 Assets Short-term lease cost Selling, general and administrative expenses or Lease operating expenses 295 Operating lease cost Selling, general and administrative expenses or Lease operating expenses 851 Finance lease cost Amortization of lease assets Depreciation, depletion, amortization and accretion 1,333 Interest on lease liabilities Interest expense 137 Net lease cost $ 2,616 Information regarding our lease terms and discount rates as of March 31, 2019 were as follows: March 31, 2019 Weighted-average remaining lease term (years) Operating leases 5.7 Finance leases 1.9 Weighted-average discount rate Operating leases 18.6 % Finance leases 5.5 % |
Supplemental Balance Sheet Information | Supplemental balance sheet information related to leases as of March 31, 2019 was as follows: Leases (in thousands) Classification March 31, 2019 Assets Operating lease assets Lease assets $ 6,272 Finance lease assets, at cost Lease assets 10,564 Accumulated amortization Lease assets (1,333 ) Finance lease assets, net Lease assets 9,231 Total lease assets $ 15,503 Liabilities Current Operating Liabilities subject to compromise $ 1,466 Finance Liabilities subject to compromise 5,099 Long-Term Operating Liabilities subject to compromise 5,255 Finance Liabilities subject to compromise 4,234 Total lease liabilities $ 16,054 |
Finance Lease Maturity | The maturity of our lease liabilities as of March 31, 2019 were as follows (in thousands): Operating Leases Finance Leases Total 2019 (remaining of year) $ 2,059 $ 4,113 $ 6,172 2020 1,772 4,400 6,172 2021 1,563 1,320 2,883 2022 1,255 30 1,285 2023 1,247 — 1,247 Thereafter 3,150 — 3,150 Total undiscounted lease liability 11,046 9,863 20,909 Imputed interest (4,325 ) (530 ) (4,855 ) Total discounted liability $ 6,721 $ 9,333 $ 16,054 |
Operating Lease Maturity | The maturity of our lease liabilities as of March 31, 2019 were as follows (in thousands): Operating Leases Finance Leases Total 2019 (remaining of year) $ 2,059 $ 4,113 $ 6,172 2020 1,772 4,400 6,172 2021 1,563 1,320 2,883 2022 1,255 30 1,285 2023 1,247 — 1,247 Thereafter 3,150 — 3,150 Total undiscounted lease liability 11,046 9,863 20,909 Imputed interest (4,325 ) (530 ) (4,855 ) Total discounted liability $ 6,721 $ 9,333 $ 16,054 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | Please see Note 10, “Leases,” for a detailed discussion of our current accounting for leases with the adoption of ASU 2016-02. Lease Payments (in thousands) 2019 $ 1,211 2020 1,149 2021 1,169 2022 1,204 2023 1,241 Thereafter 3,262 Total $ 9,236 |
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 March 31, 2019 . 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. March 31, 2019 (in thousands) April 1, 2019 - December 31, 2019 615 2020 410 Total $ 1,025 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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 March 31, 2019 : Time-Based Restricted Stock Units Weighted Average Grant Date Fair Value Non-vested at December 31, 2018 244,496 $ 16.62 Vested (1,473 ) $ 11.99 Non-vested at March 31, 2019 243,023 $ 16.65 |
Schedule of Monte Carlo Simulation Assumptions | We estimated the fair value of TSR Performance RSUs at the modification date using a Monte Carlo simulation. Assumptions used in the Monte Carlo simulation were as follows: TSR Performance RSU Replacement Awards Modification date September 11, 2018 Remaining performance period 2.31 years VNR closing price $5.40 VNR beginning TSR price $19.00 Compounded risk-free interest rate (2.31-yr) 2.75% VNR historical volatility (2.31-yr) 71.69% Fair value of unit $19.76 |
Description of the Business (De
Description of the Business (Details) | 3 Months Ended | |
Mar. 31, 2019operating_area$ / shares | Dec. 31, 2018$ / shares | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Number of operating areas | operating_area | 9 | |
Common stock, par value (usd per share) | $ / shares | $ 0.001 | $ 0.001 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Jan. 01, 2019 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Lease assets | $ 15,503 | |
Lease liability | $ 16,054 | |
ASU 2016-02 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Lease assets | $ 17,500 | |
Lease liability | $ 18,000 | |
Potato Hills Gas Gathering System | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Ownership Percentage by Parent | 51.00% |
2019 Chapter 11 Proceedings (Sc
2019 Chapter 11 Proceedings (Schedules and Statements - Claims & Claims Resolution Process) (Details) - Subsequent Event $ in Millions | May 10, 2019USD ($)claimantclaim |
Subsequent Event [Line Items] | |
Number claims filed | claim | 83 |
Amount of claims filed | $ | $ 2.3 |
Number of claimants | claimant | 73 |
2019 Chapter 11 Proceedings (Pl
2019 Chapter 11 Proceedings (Plan Support Agreement) (Details) - Subsequent Event | May 08, 2019USD ($) |
Preferred Equity Class A | |
Subsequent Event [Line Items] | |
Percent of stock issued under Plan Support Agreement | 86.10% |
Percentage of pro-rata and interest | 13.90% |
Common Stock | |
Subsequent Event [Line Items] | |
Percentage of pro-rata and interest | 10.00% |
Common Stock | Minimum | |
Subsequent Event [Line Items] | |
Percent of stock issued under Plan Support Agreement | 75.00% |
Common Stock | Maximum | |
Subsequent Event [Line Items] | |
Percent of stock issued under Plan Support Agreement | 89.00% |
Senior Note Claims | Common Stock | |
Subsequent Event [Line Items] | |
Percentage of pro-rata and interest | 15.00% |
Percentage of pro-rata and interest if rejected | 1.00% |
Revolving Credit Facility | |
Subsequent Event [Line Items] | |
Percentage of debt | 66.66% |
Percent of number of debt claims | 50.10% |
Line of Credit | Successor Credit Facility | |
Subsequent Event [Line Items] | |
Percentage of debt | 66.66% |
Percent of number of debt claims | 50.10% |
Term Loan | Term Loan | |
Subsequent Event [Line Items] | |
Percentage of debt | 66.66% |
Percent of number of debt claims | 50.10% |
Term Loan | Exit RBL/Term Loan A Facility | |
Subsequent Event [Line Items] | |
Debt instrument, face amount | $ 65,000,000 |
Term Loan | Exit Term Loan B Facility | |
Subsequent Event [Line Items] | |
Debt instrument, face amount | $ 285,000,000 |
2019 Chapter 11 Proceedings (De
2019 Chapter 11 Proceedings (Debtor-in-Possession Financing) (Details) - Debtor-in-Possession Financing - USD ($) $ in Millions | Mar. 31, 2019 | Apr. 04, 2019 |
Debt Instrument [Line Items] | ||
Commitment fee (percent) | 1.00% | |
LIBOR | ||
Debt Instrument [Line Items] | ||
Applicable margin on variable rate (percent) | 5.50% | |
Base Rate | ||
Debt Instrument [Line Items] | ||
Applicable margin on variable rate (percent) | 4.50% | |
Senior Secured Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Aggregate debt | $ 65 | |
debtor-in-possession, Minimum Liquidity | 10 | |
Senior Secured Revolving Credit Facility | Subsequent Event | ||
Debt Instrument [Line Items] | ||
Amount drawn | $ 20 | |
Roll-up Revolving Loan | ||
Debt Instrument [Line Items] | ||
Aggregate debt | $ 65 |
2019 Chapter 11 Proceedings (Ac
2019 Chapter 11 Proceedings (Acceleration of Debt) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2018 | Aug. 01, 2017 | |
Interest expense | $ 11,600 | ||
Successor Credit Facility | Line of Credit | |||
Debt amount outstanding | 677,718 | $ 682,145 | |
Term Loan | Term Loan | |||
Debt amount outstanding | 123,438 | $ 123,438 | $ 125,000 |
New Notes | Senior Notes | |||
Debt amount outstanding | $ 80,700 |
2019 Chapter 11 Proceedings (Se
2019 Chapter 11 Proceedings (Settlement of Liabilities Subject to Compromise) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Reorganizations [Abstract] | ||
Accounts payable | $ 17,000 | |
Accrued liabilities | 42,507 | |
Undistributed oil and gas revenues | 33,453 | |
Derivative liabilities | 40,428 | |
Other liabilities | 5,425 | |
Debt and accrued interest | 894,407 | |
Lease liabilities | 16,054 | |
Liabilities subject to compromise | $ 1,049,274 | $ 0 |
2019 Chapter 11 Proceedings (Re
2019 Chapter 11 Proceedings (Reorganization Items) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Reorganizations [Abstract] | ||
Professional and legal fees | $ 12,077 | |
Deferred financing costs and debt discount | 6,311 | |
Total Reorganization items | 18,388 | $ 1,707 |
Unamortized debt issuance costs and debt discounts | $ 6,300 |
Revenues (Details)
Revenues (Details) | 3 Months Ended |
Mar. 31, 2019 | |
Minimum | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation period | 30 days |
Maximum | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation period | 90 days |
Divestitures (Narrative) (Detai
Divestitures (Narrative) (Details) $ in Millions | 1 Months Ended |
Mar. 31, 2019USD ($) | |
Business Combinations [Abstract] | |
Proceeds from divestiture | $ 4.4 |
Transaction costs | $ 0.2 |
Debt (Financing Arrangements) (
Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2018 | Aug. 01, 2017 | |
Debt Instrument [Line Items] | |||
Unamortized deferred financing costs | $ 0 | $ (7,124) | |
Total debt | 881,878 | 889,635 | |
Liabilities subject to compromise | (881,878) | 0 | |
Long-term debt classified as current | 0 | (879,181) | |
Current portion of Lease Financing Obligation | (5,008) | ||
Total long-term debt | $ 0 | 5,446 | |
Lease Financing Obligations | |||
Debt Instrument [Line Items] | |||
Stated interest rate (percent) | 4.16% | ||
Maturity Date | Aug. 10, 2020 | ||
Debt amount outstanding | $ 10,454 | ||
Revolving Loan | Line of Credit | |||
Debt Instrument [Line Items] | |||
Variable interest rate (percent) | 6.53% | 6.27% | |
Maturity Date | Feb. 1, 2021 | ||
Debt amount outstanding | $ 677,718 | $ 682,145 | |
Term Loan | Term Loan | |||
Debt Instrument [Line Items] | |||
Variable interest rate (percent) | 10.28% | 9.96% | |
Maturity Date | May 1, 2021 | ||
Debt amount outstanding | $ 123,438 | $ 123,438 | $ 125,000 |
New Notes | 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) - USD ($) $ in Thousands | Aug. 01, 2017 | Mar. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | |||
Proceeds from divestiture | $ 4,400 | ||
Revolving Loan | |||
Debt Instrument [Line Items] | |||
Current borrowing capacity | $ 850,000 | 677,900 | |
Commitment fee (percent) | 0.50% | ||
Debt covenant , current ratio | 1 | ||
Revolving Loan | Minimum | |||
Debt Instrument [Line Items] | |||
Liens on oil and gas properties as percentage of total value | 95.00% | ||
Revolving Loan | Maximum | |||
Debt Instrument [Line Items] | |||
Limit on unrestricted cash and cash equivalents per agreement | $ 35,000 | ||
Revolving Loan | Line of Credit | |||
Debt Instrument [Line Items] | |||
Debt amount outstanding | 677,718 | $ 682,145 | |
Revolving Loan | Line of Credit | Base Rate | Minimum | |||
Debt Instrument [Line Items] | |||
Applicable margin on variable rate (percent) | 1.75% | ||
Revolving Loan | Line of Credit | Base Rate | Maximum | |||
Debt Instrument [Line Items] | |||
Applicable margin on variable rate (percent) | 2.75% | ||
Revolving Loan | Line of Credit | 30-day LIBOR | Minimum | |||
Debt Instrument [Line Items] | |||
Applicable margin on variable rate (percent) | 2.75% | ||
Revolving Loan | Line of Credit | 30-day LIBOR | Maximum | |||
Debt Instrument [Line Items] | |||
Applicable margin on variable rate (percent) | 3.75% | ||
Term Loan | Term Loan | |||
Debt Instrument [Line Items] | |||
Debt amount outstanding | $ 125,000 | $ 123,438 | $ 123,438 |
Required quarterly payment principal as percentage of original principal | 0.25% | ||
Term Loan | Term Loan | Base Rate | |||
Debt Instrument [Line Items] | |||
Applicable margin on variable rate (percent) | 6.50% | ||
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 - Term Loan $ in Thousands | Mar. 31, 2019USD ($) |
Debt Instrument [Line Items] | |
2019 | $ 1,250 |
2020 | 1,250 |
2021 through Maturity date | $ 120,938 |
Debt (New Notes Narrative) (Det
Debt (New Notes Narrative) (Details) - Senior Notes - USD ($) $ in Thousands | Aug. 01, 2017 | Mar. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | |||
Claims from certain eligible holders of Predecessor's second lien notes | $ 80,700 | ||
New Notes | |||
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 | ||
Redemption price subsequent to equity offering (percent) | 100.00% | ||
New Notes | 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 (Financial Debt Covenant R
Debt (Financial Debt Covenant Ratio) (Details) - Successor Credit Facility | 3 Months Ended | 4 Months Ended | 6 Months Ended | ||||
Sep. 30, 2020 | Jun. 30, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Feb. 01, 2021 | Mar. 31, 2020 | |
Debt Instrument [Line Items] | |||||||
Debt to EBITDA | 5.75 | ||||||
Forecast | |||||||
Debt Instrument [Line Items] | |||||||
Debt to EBITDA | 4.25 | 4.50 | 5 | 5.25 | 4 | 4.75 |
Debt (Schedule of Redemption Pr
Debt (Schedule of Redemption Prices) (Details) - Senior Notes - New Notes | 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% |
Twelve-month redemption period beginning Feb 15, 2023 and thereafter | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 100.00% |
Price Risk Management Activit_3
Price Risk Management Activities (Narrative) (Details) - USD ($) $ in Thousands | Apr. 01, 2019 | Mar. 31, 2019 | Dec. 31, 2018 |
Derivative [Line Items] | |||
Gross Amounts of Recognized Assets | $ 7,758 | $ 22,361 | |
Commodity Contract | |||
Derivative [Line Items] | |||
Gross Amounts of Recognized Assets | $ 7,758 | $ 22,361 | |
Subsequent Event | Commodity Contract | |||
Derivative [Line Items] | |||
Estimate of possible loss due to counterparty failure to perform, maximum | $ 53,900 |
Price Risk Management Activit_4
Price Risk Management Activities (Commodity Derivatives) (Details) MMBTU in Thousands | Mar. 31, 2019MMBTU$ / bbl$ / MMBTU$ / galgalbbl |
Fixed-Price Swaps | April 1, 2019 - December 31, 2019 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 36,429 |
Weighted Average Fixed Price | $ / MMBTU | 2.75 |
Fixed-Price Swaps | April 1, 2019 - December 31, 2019 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,393,300 |
Weighted Average Fixed Price | 48.49 |
Fixed-Price Swaps | April 1, 2019 - December 31, 2019 | NGLs | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | gal | 14,666,518 |
Weighted Average Fixed Price | $ / gal | 0.91 |
Fixed-Price Swaps | January 1, 2020 - December 31, 2020 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 47,228 |
Weighted Average Fixed Price | $ / MMBTU | 2.75 |
Fixed-Price Swaps | January 1, 2020 - December 31, 2020 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 1,393,800 |
Weighted Average Fixed Price | 49.53 |
Fixed-Price Swaps | January 1, 2020 - December 31, 2020 | NGLs | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | gal | 0 |
Weighted Average Fixed Price | $ / gal | 0 |
Basis Swaps | April 1, 2019 - December 31, 2019 | Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 11,000 |
Weighted Average Fixed Price | $ / MMBTU | 0.57 |
Basis Swaps | April 1, 2019 - December 31, 2019 | Enable East Gas and NYMEX Henry Hub Basis Differential | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 4,125 |
Weighted Average Fixed Price | $ / MMBTU | 0.25 |
Basis Swaps | April 1, 2019 - December 31, 2019 | WTI Midland and WTI Cushing Basis Differential | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 343,750 |
Weighted Average Fixed Price | 5.78 |
Basis Swaps | April 1, 2019 - December 31, 2019 | WTI and WCS Basis Differential | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 137,500 |
Weighted Average Fixed Price | 20.40 |
Basis Swaps | January 1, 2020 - December 31, 2020 | WTI Midland and WTI Cushing Basis Differential | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 366,000 |
Weighted Average Fixed Price | 0.10 |
Collars | April 1, 2019 - December 31, 2019 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 4,125 |
Floor Price | $ / MMBTU | 2.60 |
Ceiling Price | $ / MMBTU | 3 |
Collars | April 1, 2019 - December 31, 2019 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 424,370 |
Floor Price | 43.78 |
Ceiling Price | 54.03 |
Collars | January 1, 2020 - December 31, 2020 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 5,490 |
Floor Price | $ / MMBTU | 2.60 |
Ceiling Price | $ / MMBTU | 3 |
Collars | January 1, 2020 - December 31, 2020 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 659,340 |
Floor Price | 44.17 |
Ceiling Price | 55 |
Collars | January 1, 2021 - December 31, 2021 | Gas | |
Derivative [Line Items] | |
Portion of Future Gas Production Being Hedged | MMBTU | 1,825 |
Floor Price | $ / MMBTU | 2.60 |
Ceiling Price | $ / MMBTU | 3.07 |
Collars | January 1, 2021 - December 31, 2021 | Oil | |
Derivative [Line Items] | |
Portion of Future Oil and Gas Production Being Hedged | bbl | 294,536 |
Floor Price | 55.25 |
Ceiling Price | 63.76 |
Price Risk Management Activit_5
Price Risk Management Activities (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Offsetting Derivative Assets: | ||
Gross Amounts of Recognized Assets | $ 7,758 | $ 22,361 |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | (5,810) | (9,308) |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | 1,948 | 13,053 |
Offsetting Derivative Liabilities: | ||
Gross Amounts of Recognized Liabilities | (46,238) | (15,791) |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | 5,810 | 9,308 |
Net Amounts Presented in the Condensed Consolidated Balance Sheets(1) | (40,428) | (6,483) |
Commodity Contract | ||
Offsetting Derivative Assets: | ||
Gross Amounts of Recognized Assets | 7,758 | 22,361 |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | (5,810) | (9,308) |
Net Amounts Presented in the Condensed Consolidated Balance Sheets | 1,948 | 13,053 |
Offsetting Derivative Liabilities: | ||
Gross Amounts of Recognized Liabilities | (46,238) | (15,791) |
Gross Amounts Offset in the Condensed Consolidated Balance Sheets | 5,810 | 9,308 |
Net Amounts Presented in the Condensed Consolidated Balance Sheets(1) | $ (40,428) | $ (6,483) |
Price Risk Management Activit_6
Price Risk Management Activities (Change in Fair Value of Derivatives) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | Dec. 31, 2018 | |
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | |||
Derivative asset (liability) at beginning of period, net | $ 6,570 | $ (64,437) | $ (64,437) |
Purchases | |||
Net losses on commodity and interest rate derivative contracts | (61,139) | (9,259) | |
Settlements | |||
Cash settlements paid on matured commodity derivative contracts | 16,089 | $ 9,292 | 80,266 |
Derivative asset (liability) at end of period, net | $ (38,480) | $ 6,570 |
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 | Mar. 31, 2019 | Dec. 31, 2018 |
Derivative Asset [Abstract] | ||
Commodity price derivative contracts | $ 1,948 | $ 13,053 |
Total derivative instruments | 1,948 | 13,053 |
Liabilities: | ||
Commodity price derivative contracts | (40,428) | (6,483) |
Total derivative instruments | (40,428) | (6,483) |
Fair Value Measurements Using Level 2 | ||
Derivative Asset [Abstract] | ||
Commodity price derivative contracts | 1,948 | 13,053 |
Total derivative instruments | 1,948 | 13,053 |
Liabilities: | ||
Commodity price derivative contracts | (40,428) | (6,483) |
Total derivative instruments | $ (40,428) | $ (6,483) |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Impairment of oil and natural gas properties | $ 438 | $ 14,601 |
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 | 1,100 | 73,000 |
Oil and natural gas properties, fair value | $ 700 | $ 58,400 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2019 | Dec. 31, 2018 | |
Roll-forward of asset retirement obligations: | ||
Asset retirement obligation, beginning balance | $ 143,208 | $ 157,424 |
Liabilities added during the current period | 65 | 610 |
Accretion expense | 2,180 | 9,295 |
Liabilities related to assets divested | (294) | (16,687) |
Retirements | (118) | (2,499) |
Change in estimate | (4,935) | |
Asset retirement obligation, ending balance | 145,041 | 143,208 |
Less: current obligations | (4,426) | |
Long-term asset retirement obligation | $ 140,615 | $ 139,433 |
Future inflation factor | 1.60% | 1.70% |
Credit-adjusted risk-free interest rate | 6.80% | |
Minimum | ||
Roll-forward of asset retirement obligations: | ||
Credit-adjusted risk-free interest rate | 6.50% | |
Maximum | ||
Roll-forward of asset retirement obligations: | ||
Credit-adjusted risk-free interest rate | 7.10% |
Leases (Lease Expense) (Details
Leases (Lease Expense) (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2019USD ($) | |
Lessee, Lease, Description [Line Items] | |
Short-term lease cost | $ 295 |
Operating lease cost | 851 |
Amortization of lease assets | 1,333 |
Interest on lease liabilities | 137 |
Net lease cost | $ 2,616 |
Minimum | |
Lessee, Lease, Description [Line Items] | |
Renewal term | 1 year |
Maximum | |
Lessee, Lease, Description [Line Items] | |
Renewal term | 10 years |
Leases (Lease Terms and Discoun
Leases (Lease Terms and Discount Rates) (Details) | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Weighted-average remaining lease term, Operating leases | 5 years 7 months 27 days |
Weighted-average remaining lease term, Finance leases | 1 year 10 months 9 days |
Weighted-average discount rate, Operating leases | 18.60% |
Weighted-average discount rate, Finance leases | 5.50% |
Leases (Supplemental Balance Sh
Leases (Supplemental Balance Sheet Information) (Details) $ in Thousands | Mar. 31, 2019USD ($) |
Leases [Abstract] | |
Operating lease assets | $ 6,272 |
Finance lease assets, at cost | 10,564 |
Accumulated amortization | (1,333) |
Finance lease assets, net | 9,231 |
Total lease assets | 15,503 |
Operating, current | 1,466 |
Finance, current | 5,099 |
Operating, long-term | 5,255 |
Finance, long-term | 4,234 |
Total lease liabilities | $ 16,054 |
Leases (Maturity) (Details)
Leases (Maturity) (Details) $ in Thousands | Mar. 31, 2019USD ($) |
Operating Leases | |
2019 (remaining of year) | $ 2,059 |
2020 | 1,772 |
2021 | 1,563 |
2022 | 1,255 |
2023 | 1,247 |
Thereafter | 3,150 |
Total undiscounted lease liability | 11,046 |
Imputed interest | (4,325) |
Total discounted liability | 6,721 |
Finance Leases | |
2019 (remaining of year) | 4,113 |
2020 | 4,400 |
2021 | 1,320 |
2022 | 30 |
2023 | 0 |
Thereafter | 0 |
Total undiscounted lease liability | 9,863 |
Imputed interest | (530) |
Total discounted liability | 9,333 |
Total | |
2019 (remaining of year) | 6,172 |
2020 | 6,172 |
2021 | 2,883 |
2022 | 1,285 |
2023 | 1,247 |
Thereafter | 3,150 |
Total undiscounted lease liability | 20,909 |
Imputed interest | (4,855) |
Total discounted liability | $ 16,054 |
Leases (Supplemental Cash Flow)
Leases (Supplemental Cash Flow) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Leases [Abstract] | ||
Operating cash flows from operating leases | $ 1,045 | |
Operating cash flows from finance leases | 137 | |
Financing cash flows from finance leases | $ 1,231 | |
Rent expense | $ 500 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2019 | Dec. 31, 2018 | |
Other Commitments [Line Items] | ||
Lease commitments | $ 9,236 | |
Remaining term of contracts | 1 year | |
Estimated commitments to third-party operators under joint operating agreements, due in the next 12 months | $ 12,000 | |
Pinedale Field Drilling And Green RIver Basin | ||
Other Commitments [Line Items] | ||
Estimated commitments to third-party operators under joint operating agreements, due in the next 12 months | $ 5,000 |
Commitments and Contingencies_3
Commitments and Contingencies (Lease Commitments) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2019 | $ 1,211 |
2020 | 1,149 |
2021 | 1,169 |
2022 | 1,204 |
2023 | 1,241 |
Thereafter | 3,262 |
Total | $ 9,236 |
Commitments and Contingencies_4
Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands | Mar. 31, 2019USD ($) |
Gross future minimum transportation demand | |
April 1, 2019 - December 31, 2019 | $ 615 |
Due 2020 | 410 |
Total | $ 1,025 |
Stockholders' Equity (Warrant A
Stockholders' Equity (Warrant Agreement) (Details) - $ / shares | Aug. 01, 2017 | Mar. 31, 2019 |
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 (Earning P
Stockholders' Equity (Earning Per Share/Unit) (Details) - shares | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
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) | 301,065 | 173,629 |
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 | 1,300,000 |
Share-Based Compensation (MIP R
Share-Based Compensation (MIP Restricted Stock) (Details) - Restricted Stock Units (RSUs) | 3 Months Ended |
Mar. 31, 2019$ / sharesshares | |
Time-Based Restricted Stock Units | |
Non-vested units at beginning of period (in units) | shares | 244,496 |
Vested (in units) | shares | (1,473) |
Non-vested units at end of period (in units) | shares | 243,023 |
Weighted Average Grant Date Fair Value | |
Non-vested units at beginning of period (in dollars per unit) | $ / shares | $ 16.62 |
Vested (in dollars per unit) | $ / shares | 11.99 |
Non-vested units at end of period (in dollars per unit) | $ / shares | $ 16.65 |
Share-Based Compensation (Narra
Share-Based Compensation (Narrative) (Details) - USD ($) $ in Millions | Sep. 11, 2018 | Jan. 31, 2018 | Mar. 31, 2019 | Mar. 31, 2018 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 0.6 | $ 0.5 | ||
Restricted Stock Units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 3.1 | |||
Unrecognized compensation cost recognition period (in years) | 1 year 8 months | |||
TSR Performance RSU Replacement Awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 1 | |||
Unrecognized compensation cost recognition period (in years) | 2 years 3 months 21 days | 1 year 9 months | ||
TSR Performance RSU Replacement Awards | Management | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Term of award (in years) | P3Y | |||
Minimum | TSR Performance RSU Replacement Awards | Management | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total award as percent of initial grant | 0.00% | |||
Maximum | TSR Performance RSU Replacement Awards | Management | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total award as percent of initial grant | 200.00% |
Share-Based Compensation (Monte
Share-Based Compensation (Monte Carlo Simulation Assumptions) (Details) - TSR Performance RSU Replacement Awards - $ / shares | Sep. 11, 2018 | Mar. 31, 2019 | Jan. 31, 2018 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining performance period | 2 years 3 months 21 days | 1 year 9 months | |
Closing price of our common stock on grant date (in dollars per share) | $ 5.40 | $ 19 | |
Risk-free interest rate (percent) | 2.75% | ||
Volatility (percent) | 71.69% | ||
Fair value of unit (in dollars per share) | $ 19.76 |