(Mark One)
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ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2017
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Or
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p
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to .
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Delaware
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80-0411494
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(State or Other Jurisdiction of
Incorporation or Organization)
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(I.R.S. Employer
Identification No.)
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5847 San Felipe, Suite 3000
Houston, Texas
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77057
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(Address of Principal Executive Offices)
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(Zip Code)
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Yes
o
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No
x
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Yes
o
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No
x
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Yes
x
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No
o
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Yes
x
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No
o
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o
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
o
(Do not check if smaller reporting company)
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Smaller reporting company
x
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Emerging growth company
o
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o
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Yes
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No
x
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Yes
x
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No
o
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Caption
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•
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our ability to obtain sufficient financing to execute our business plan post-emergence;
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our ability to meet our liquidity needs;
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our ability to access the public capital markets;
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risks relating to any of our unforeseen liabilities;
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declines in oil, natural gas liquids (“NGLs”) or natural gas prices;
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the level of success in exploration, development and production activities;
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adverse weather conditions that may negatively impact development or production activities;
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the timing of exploitation and development expenditures;
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inaccuracies of reserve estimates or assumptions underlying them;
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revisions to reserve estimates as a result of changes in commodity prices;
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impacts to financial statements as a result of impairment write-downs;
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risks related to the level of indebtedness and periodic redeterminations of the borrowing base under our credit agreements;
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ability to comply with restrictive covenants contained in the agreements governing our indebtedness that may adversely affect operational flexibility;
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ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget;
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ability to obtain external capital to finance exploration and development operations and acquisitions;
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•
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federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing;
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failure of properties to yield oil or natural gas in commercially viable quantities;
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uninsured or underinsured losses resulting from oil and natural gas operations;
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ability to access oil and natural gas markets due to market conditions or operational impediments;
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the impact and costs of compliance with laws and regulations governing oil and natural gas operations;
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ability to replace oil and natural gas reserves;
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any loss of senior management or technical personnel;
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competition in the oil and natural gas industry;
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•
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risks arising out of hedging transactions;
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the costs and effects of litigation;
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sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance; and
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costs of tax treatment as a corporation.
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/day
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= per day
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Mcf
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= thousand cubic feet
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Bbls
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= barrels
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Mcfe
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= thousand cubic feet of natural gas equivalents
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Bcf
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= billion cubic feet
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MMBbls
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= million barrels
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Bcfe
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= billion cubic feet equivalents
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MMBOE
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= million barrels of oil equivalent
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BOE
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= barrel of oil equivalent
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MMBtu
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= million British thermal units
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Btu
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= British thermal unit
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MMcf
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= million cubic feet
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MBbls
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= thousand barrels
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MMcfe
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= million cubic feet of natural gas equivalents
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MBOE
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= thousand barrels of oil equivalent
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NGLs
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= natural gas liquids
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•
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the Green River Basin in Wyoming;
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•
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the Piceance Basin in Colorado;
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•
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the Permian Basin in West Texas and New Mexico;
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the Arkoma Basin in Arkansas and Oklahoma;
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the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;
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•
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the Big Horn Basin in Wyoming and Montana;
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the Anadarko Basin in Oklahoma and North Texas;
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•
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the Wind River Basin in Wyoming; and
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the Powder River Basin in Wyoming.
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•
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The Predecessor transferred all of its membership interests in VNG, a Kentucky limited liability company and the Predecessor’s wholly owned first-tier subsidiary, to the Successor (formerly known as VNR Finance Corp.). VNG directly or indirectly owned all of the other subsidiaries of the Predecessor. As a result of the foregoing and certain other transactions, the Successor is no longer a subsidiary of the Predecessor and now owns all of the former subsidiaries of the Predecessor;
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•
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VNG, as borrower, entered into that certain Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loan”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date was $850.0 million and the aggregate principal amount of Revolving Loans
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•
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The Successor issued approximately $80.7 million aggregate principal amount of new 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes” or “Senior Notes due 2024”) to certain eligible holders of their outstanding Old Second Lien Notes in full satisfaction of their claim of approximately $80.7 million related to the Old Second Lien Notes held by such holders;
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•
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The Predecessor’s Senior Notes were cancelled and the holders of the Senior Notes received their pro rata share of 97.0% (subject to dilution by the other transactions referred to in this section) of the Common Stock, in full and final satisfaction of their claims;
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The Predecessor completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $275.0 million of gross proceeds. The rights offering resulted in subscriptions for 18.1 million shares of Successor common stock, representing approximately 89.92% of outstanding shares of Common Stock, to holders of claims arising under the Senior Notes and to the Backstop Parties;
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The Successor entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain recipients of shares of its Common Stock distributed on the Effective Date that were parties to the Amended and Restated Backstop Commitment Agreement (including the Backstop Parties and certain of their affiliates and related funds), in accordance with the terms set forth in the Final Plan (collectively, the “Registration Rights Holders”). Pursuant to the Registration Rights Agreement, we agreed to, among other things, file a registration statement with the SEC within 90 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined in the Registration Rights Agreement). We filed the registration statement on October 30, 2017;
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Additional shares of Common Stock, representing 10% of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);
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All outstanding Preferred Units (defined below) issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% (subject to dilution by the other transactions referred to in this section) of outstanding shares of Common Stock and (ii) Preferred Unit Warrants (as defined below), in full and final satisfaction of their interests;
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All common equity of the Predecessor issued and outstanding immediately prior to the Effective Date was cancelled and the holders of the common equity received Common Unit Warrants (as defined below), in full and final satisfaction of their interests;
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The Successor entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Successor issued (i) to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), (B) 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and (C) 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with the Series A Preferred Units and Series B Preferred Units, the “Preferred Units”), three and a half year warrants (the “Preferred Unit Warrants”), which will be exercisable to purchase up to 621,649 shares of the Common Stock as of the Effective Date; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which will be exercisable to purchase up to 640,876 shares of the Common Stock as of the Effective Date. The expiration date of the Warrants will be February 1, 2021. The strike price for the Preferred Unit Warrants is $44.25, and the strike price for the Common Unit Warrants is $61.45;
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By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. A new board was established for the Successor Company;
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Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders; and
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The Successor issued 20.1 million shares of common stock, $0.001 par value (“Common Stock”).
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We applied fresh-start accounting in accordance with Accounting Standards Codification (“ASC”) 852, which resulted in our becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of our emergence from the Chapter 11 Cases on August 1, 2017. The fair values of our assets and liabilities differ materially from the recorded values of our assets and liabilities as reflected in our Predecessor’s historical consolidated balance sheets;
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•
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We changed our method of accounting for natural gas and oil properties from the full cost method of accounting to the successful efforts method of accounting;
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We adopted the new standard for revenue recognition under Accounting Standards Codification 606 (“ASC 606”) upon emergence. The new guidance requires us to recognize revenue upon transfer of goods or services to a customer at an amount that reflects the expected consideration to be received in exchange for those goods or services; and
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We changed from a pass-through entity for tax purposes to a C-corporation and, accordingly, a taxable entity.
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Manage our portfolio of assets actively, including divesting certain non-core assets to focus on the development of our core inventory of undeveloped locations, specifically in the Pinedale and Mamm Creek fields, located in the Green River Basin and the Piceance Basin, respectively, and Arkoma Woodford;
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Continue to efficiently operate several of our long-lived, low decline oil and gas fields for production and cash flow;
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Pursue a capital structure which affords financial flexibility; and
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Use hedging strategies to reduce the volatility in our revenues resulting from changes in oil, natural gas and NGLs prices.
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2017 Net Production
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Natural Gas
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Oil
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NGLs
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Total
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Net Estimated
Proved Reserves
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PV-10
Value
(b)
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|||||||
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(MMcf)
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(MBbls)
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(MBbls)
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(MMcfe)
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(MMcfe)
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(in millions)
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Green River Basin
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38,303
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359
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549
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43,754
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750,083
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$
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374.2
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Piceance Basin
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18,285
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199
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1,345
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27,544
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292,424
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$
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222.4
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Permian Basin
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5,872
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1,272
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557
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16,849
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144,095
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$
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164.7
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Arkoma Basin
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15,165
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3
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188
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16,309
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337,571
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$
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137.4
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Gulf Coast Basin
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5,263
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652
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481
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12,057
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133,731
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$
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120.7
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Big Horn Basin
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209
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777
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96
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5,446
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83,348
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$
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119.5
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Williston Basin
(a)
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222
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363
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4
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2,429
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—
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$
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—
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Anadarko Basin
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1,837
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130
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43
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2,874
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36,300
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$
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33.4
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Wind River Basin
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2,552
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13
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57
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2,970
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25,976
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$
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14.6
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Powder River Basin
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6,302
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—
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—
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6,302
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18,015
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$
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7.9
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Total
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94,010
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3,768
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3,320
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136,534
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1,821,543
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$
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1,194.8
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(a)
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In December 2017, we completed the sale of our oil and natural gas properties in the Williston Basin in North Dakota and Montana (“Williston Divestiture”).
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(b)
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Present Value of Future Net Reserves (“PV-10”) is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”), and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows. We believe the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. We use the PV-10 Value for comparison against our debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment from our oil and natural gas properties. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report.
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Reserve Data:
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Estimated net proved reserves:
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Crude oil (MMBbls)
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39.0
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Natural gas (Bcf)
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1,357.6
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NGLs (MMBbls)
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38.4
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Total (Bcfe)
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1,821.5
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Proved developed (Bcfe)
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1,225.3
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Proved undeveloped (Bcfe)
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596.2
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Proved developed reserves as % of total proved reserves
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67
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%
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PV-10
(1)
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$
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1,194.8
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Less: Future income taxes (discounted at 10%)
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(121.2
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)
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Standardized Measure (in millions)
(2)
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$
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1,073.6
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Representative Oil and Natural Gas Prices
(3)
:
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Oil—WTI per Bbl
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$
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51.22
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Natural gas—Henry Hub per MMBtu
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$
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2.99
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NGLs—Volume-weighted average price per Bbl
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$
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19.24
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(1)
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PV-10 is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”, and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows.
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(2)
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Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) (using the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”) and calculated net of the estimated future costs incurred in developing, producing and abandoning the proved reserves. Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Item 1. Business—Operations—Price Risk Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
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(3)
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Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month average price for January through December
2017
, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using differentials to the oil 12-month average price per Bbl of
$51.22
.
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Estimated Proved Developed
Reserve Quantities
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Estimated Proved Undeveloped
Reserve Quantities
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Estimated Proved Reserve Quantities
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Natural Gas
(Bcf)
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Oil
(MMBbls)
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NGLs
(MMBbls)
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Total
(Bcfe)
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Natural Gas
(Bcf)
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Oil
(MMBbls)
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NGLs
(MMBbls)
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Total
(Bcfe)
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Total
(Bcfe)
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|||||||||
Operating Basin
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Green River Basin
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309.3
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2.9
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|
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4.9
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355.7
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343.1
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|
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3.5
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|
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5.0
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394.4
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|
|
750.1
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|
Piceance Basin
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182.7
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|
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1.5
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|
|
14.1
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|
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276.2
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|
|
10.3
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|
|
0.1
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|
|
0.9
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|
|
16.2
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|
|
292.4
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|
Permian Basin
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51.0
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|
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10.8
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|
|
4.5
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|
|
143.1
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|
|
0.1
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|
|
0.1
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|
|
0.1
|
|
|
1.0
|
|
|
144.1
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|
Arkoma Basin
|
|
175.5
|
|
|
0.1
|
|
|
1.9
|
|
|
187.3
|
|
|
150.2
|
|
|
—
|
|
|
—
|
|
|
150.2
|
|
|
337.5
|
|
Gulf Coast Basin
|
|
49.2
|
|
|
6.0
|
|
|
3.3
|
|
|
105.0
|
|
|
17.3
|
|
|
0.9
|
|
|
1.0
|
|
|
28.8
|
|
|
133.8
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|
Big Horn Basin
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3.4
|
|
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11.6
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|
|
1.6
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|
|
82.4
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|
|
0.3
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|
|
0.1
|
|
|
—
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|
|
0.9
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|
|
83.3
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|
Anadarko Basin
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23.9
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|
|
1.4
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|
|
0.6
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|
|
36.1
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|
|
0.2
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|
|
—
|
|
|
—
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|
|
0.2
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|
|
36.3
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|
Wind River Basin
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|
22.9
|
|
|
0.1
|
|
|
0.4
|
|
|
26.0
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|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.0
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|
Powder River Basin
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|
13.5
|
|
|
—
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|
|
—
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|
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13.5
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|
|
4.5
|
|
|
—
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|
|
—
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|
|
4.5
|
|
|
18.0
|
|
Total
|
|
831.4
|
|
|
34.4
|
|
|
31.3
|
|
|
1,225.3
|
|
|
526.0
|
|
|
4.7
|
|
|
7.0
|
|
|
596.2
|
|
|
1,821.5
|
|
|
|
PV-10 Value
(1)
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||||||||||
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||
Operating Basin
|
|
(in millions)
|
||||||||||
Green River Basin
|
|
$
|
277.0
|
|
|
$
|
97.2
|
|
|
$
|
374.2
|
|
Piceance Basin
|
|
219.7
|
|
|
2.7
|
|
|
222.4
|
|
|||
Permian Basin
|
|
163.7
|
|
|
1.0
|
|
|
164.7
|
|
|||
Arkoma Basin
|
|
115.9
|
|
|
21.5
|
|
|
137.4
|
|
|||
Gulf Coast Basin
|
|
106.3
|
|
|
14.4
|
|
|
120.7
|
|
|||
Big Horn Basin
|
|
117.9
|
|
|
1.6
|
|
|
119.5
|
|
|||
Anadarko Basin
|
|
33.0
|
|
|
0.4
|
|
|
33.4
|
|
|||
Wind River Basin
|
|
14.6
|
|
|
—
|
|
|
14.6
|
|
|||
Powder River Basin
|
|
6.7
|
|
|
1.2
|
|
|
7.9
|
|
|||
Total
|
|
$
|
1,054.8
|
|
|
$
|
140.0
|
|
|
$
|
1,194.8
|
|
(1)
|
PV-10 is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”, and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included Part II, Item 8 of this Annual Report.
|
|
|
Net Production
(1)
|
|
Average Realized Sales Prices
(2)
|
|
Production Cost
(3)
|
||||||||||||||||||||||
|
|
Crude Oil
Bbls/day
|
|
Natural Gas
Mcf/day
|
|
NGLs
Bbls/day
|
|
Crude Oil
Per Bbl
|
|
Natural Gas
Per Mcf
|
|
NGLs
Per Bbl
|
|
Per Mcfe
|
||||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Pinedale (Green River Basin)
|
|
796
|
|
|
92,038
|
|
|
1,310
|
|
|
$
|
46.15
|
|
|
$
|
2.37
|
|
|
$
|
18.91
|
|
|
$
|
0.47
|
|
|||
Mamm Creek (Piceance Basin)
|
|
535
|
|
|
45,704
|
|
|
3,676
|
|
|
$
|
41.47
|
|
|
$
|
2.27
|
|
|
$
|
14.16
|
|
|
$
|
0.56
|
|
|||
All other fields
|
|
8,993
|
|
|
119,816
|
|
|
4,108
|
|
|
$
|
42.57
|
|
|
$
|
2.22
|
|
|
$
|
25.06
|
|
|
$
|
1.60
|
|
|||
Total
|
|
10,324
|
|
|
257,558
|
|
|
9,094
|
|
|
$
|
42.38
|
|
|
$
|
2.28
|
|
|
$
|
19.77
|
|
|
$
|
1.08
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Pinedale (Green River Basin)
|
|
844
|
|
|
97,323
|
|
|
958
|
|
|
$
|
59.58
|
|
|
$
|
3.40
|
|
|
$
|
(1.72
|
)
|
|
$
|
0.44
|
|
|||
Mamm Creek (Piceance Basin)
|
|
579
|
|
|
50,166
|
|
|
3,746
|
|
|
$
|
52.21
|
|
|
$
|
2.39
|
|
|
$
|
11.65
|
|
|
$
|
0.53
|
|
|||
All other fields
|
|
11,308
|
|
|
147,885
|
|
|
5,449
|
|
|
$
|
53.34
|
|
|
$
|
2.85
|
|
|
$
|
16.86
|
|
|
$
|
1.40
|
|
|||
Total
|
|
12,731
|
|
|
295,374
|
|
|
10,153
|
|
|
$
|
53.20
|
|
|
$
|
2.95
|
|
|
$
|
13.19
|
|
|
$
|
1.01
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pinedale (Green River Basin)
|
|
804
|
|
|
98,266
|
|
|
1,932
|
|
|
$
|
58.87
|
|
|
$
|
2.37
|
|
|
$
|
0.26
|
|
|
$
|
0.54
|
|
|||
Mamm Creek (Piceance Basin)
|
|
649
|
|
|
58,764
|
|
|
3,701
|
|
|
$
|
49.30
|
|
|
$
|
1.96
|
|
|
$
|
12.18
|
|
|
$
|
0.43
|
|
|||
All other fields
|
|
9,529
|
|
|
135,066
|
|
|
3,927
|
|
|
$
|
57.24
|
|
|
$
|
2.07
|
|
|
$
|
21.71
|
|
|
$
|
1.41
|
|
|||
Total
|
|
10,982
|
|
53,695
|
|
292,096
|
|
84
|
|
9,560
|
|
45.11
|
|
$
|
56.89
|
|
|
$
|
3.13
|
|
|
$
|
13.68
|
|
|
$
|
0.96
|
|
(1)
|
Average daily production calculated based on 365 days for
2017
, 366 days for
2016
, and 365 days for
2015
, and includes production for all of our acquisitions from the closing dates of the acquisitions.
|
(2)
|
Average realized sales prices above include the impact of hedges, allocated proportionately by field, but exclude the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. The average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31,
2017
Compared to Year Ended December 31,
2016
” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31,
2016
compared to Year Ended December 31,
2015
.”
|
(3)
|
Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).
|
|
|
Natural Gas Wells
|
|
Oil Wells
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Green River Basin
|
|
2,835
|
|
|
411
|
|
|
22
|
|
|
21
|
|
|
2,857
|
|
|
432
|
|
Piceance Basin
|
|
1,036
|
|
|
922
|
|
|
3
|
|
|
3
|
|
|
1,039
|
|
|
925
|
|
Permian Basin
|
|
682
|
|
|
373
|
|
|
2,501
|
|
|
731
|
|
|
3,183
|
|
|
1,104
|
|
Arkoma Basin
|
|
1,431
|
|
|
325
|
|
|
8
|
|
|
2
|
|
|
1,439
|
|
|
327
|
|
Gulf Coast Basin
|
|
770
|
|
|
281
|
|
|
141
|
|
|
60
|
|
|
911
|
|
|
341
|
|
Big Horn Basin
|
|
9
|
|
|
5
|
|
|
275
|
|
|
194
|
|
|
284
|
|
|
199
|
|
Anadarko Basin
|
|
539
|
|
|
72
|
|
|
265
|
|
|
14
|
|
|
804
|
|
|
86
|
|
Wind River Basin
|
|
136
|
|
|
127
|
|
|
6
|
|
|
6
|
|
|
142
|
|
|
133
|
|
Powder River Basin
|
|
628
|
|
|
355
|
|
|
—
|
|
|
—
|
|
|
628
|
|
|
355
|
|
Total
|
|
8,066
|
|
|
2,871
|
|
|
3,221
|
|
|
1,031
|
|
|
11,287
|
|
|
3,902
|
|
|
|
Developed Acreage
(1)
|
|
Undeveloped
Acreage
(2)
|
|
Total Acreage
|
||||||||||||
|
|
Gross
(3)
|
|
Net
(4)
|
|
Gross
(3)
|
|
Net
(4)
|
|
Gross
(3)
|
|
Net
(4)
|
||||||
Green River Basin
|
|
60,730
|
|
|
24,837
|
|
|
65,690
|
|
|
10,333
|
|
|
126,420
|
|
|
35,170
|
|
Piceance Basin
|
|
16,112
|
|
|
10,477
|
|
|
9,208
|
|
|
6,878
|
|
|
25,320
|
|
|
17,355
|
|
Permian Basin
|
|
315,470
|
|
|
217,364
|
|
|
24,418
|
|
|
15,340
|
|
|
339,888
|
|
|
232,704
|
|
Arkoma Basin
|
|
373,257
|
|
|
170,927
|
|
|
15,766
|
|
|
8,454
|
|
|
389,023
|
|
|
179,381
|
|
Gulf Coast Basin
|
|
138,440
|
|
|
56,267
|
|
|
23,114
|
|
|
13,479
|
|
|
161,554
|
|
|
69,746
|
|
Big Horn Basin
|
|
23,392
|
|
|
14,559
|
|
|
1,120
|
|
|
1,073
|
|
|
24,512
|
|
|
15,632
|
|
Anadarko Basin
|
|
67,946
|
|
|
18,389
|
|
|
31,938
|
|
|
8,363
|
|
|
99,884
|
|
|
26,752
|
|
Wind River Basin
|
|
22,989
|
|
|
21,026
|
|
|
64,542
|
|
|
41,439
|
|
|
87,531
|
|
|
62,465
|
|
Powder River Basin
|
|
65,106
|
|
|
37,868
|
|
|
49,181
|
|
|
28,998
|
|
|
114,287
|
|
|
66,866
|
|
Total
|
|
1,083,442
|
|
|
571,714
|
|
|
284,977
|
|
|
134,357
|
|
|
1,368,419
|
|
|
706,071
|
|
(1)
|
Developed acres are acres spaced or assigned to productive wells.
|
(2)
|
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such leasehold acreage contains proved reserves.
|
(3)
|
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
|
(4)
|
A net acre is deemed to exist when the sum of the fractional ownership workings interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
Gross wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
209
|
|
|
137
|
|
|
169
|
|
Dry
|
|
1
|
|
|
—
|
|
|
—
|
|
Total
|
|
210
|
|
|
137
|
|
|
169
|
|
Net Development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
37.2
|
|
|
15.7
|
|
|
23.6
|
|
Dry
|
|
1
|
|
|
—
|
|
|
—
|
|
Total
|
|
38.2
|
|
|
15.7
|
|
|
23.6
|
|
Type of Arrangement
|
|
Pipeline System /Location
|
|
Deliverable Market
|
|
Gross Deliveries (MMBtu/d)
|
|
Term
|
Firm Transport
|
|
WIC Medicine Bow
|
|
Rocky Mountains
|
|
25,000
|
|
01/18 – 06/20
|
Firm Transport
|
|
Cheyenne Plains
|
|
Midcontinent
|
|
5,000
|
|
01/18 – 05/18
|
•
|
realize faster connection of newly drilled wells to the existing system;
|
•
|
control pipeline operating pressures and capacity to maximize production;
|
•
|
control compression costs and fuel use;
|
•
|
maintain system integrity;
|
•
|
control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and
|
•
|
track sales volumes and receipts closely to assure all production values are realized.
|
•
|
require the acquisition of permits before commencing drilling or other regulated activities;
|
•
|
require the installation of expensive pollution control equipment and performance of costly remedial measures to mitigate or prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;
|
•
|
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
|
•
|
limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
|
•
|
impose specific health and safety criteria addressing worker protection;
|
•
|
impose substantial liabilities for pollution resulting from operations; and
|
•
|
require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement for operations affecting federal lands or leases.
|
•
|
Our Elk Basin assets include a natural gas processing plant. Previous environmental investigations identified historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected
|
•
|
In addition, we own and operate the Fairway natural gas processing plant in the Gulf Coast Basin, for which we have reserved abandonment costs.
|
•
|
We continue to operate a groundwater remediation project at our Big Escambia Creek gas plant. This release occurred when a prior owner operated the Big Escambia Creek gas plant. We operate our pump and treat system to treat groundwater under the supervision of the Alabama Department of Environmental Management. We conducted repairs on the existing system in 2017 to help reduce the downtimes and increase rates of water volume treated.
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells; and
|
•
|
notice to surface owners and other third parties.
|
•
|
Health, Safety, and Environmental Committee Charter;
|
•
|
Strategic Opportunities Committee Charter;
|
•
|
key suppliers, vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;
|
•
|
our ability to renew existing contracts and compete for new business may be adversely affected;
|
•
|
our ability to attract, motivate and/or retain key executives and employees may be adversely affected;
|
•
|
employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
|
•
|
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
|
•
|
We adopted fresh-start accounting in accordance with ASC 852, which resulted in our becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of our emergence from the Chapter 11 Cases on August 1, 2017. The fair values of our assets and liabilities differ materially from the recorded values of our assets and liabilities as reflected in our Predecessor’s historical consolidated balance sheets.
|
•
|
We changed our method of accounting for natural gas and oil properties from the full cost method to the successful efforts method. We recorded significant impairments of our natural gas and oil properties under the full cost method, which might not have been required under the successful efforts method;
|
•
|
We elected to adopt the new standard for revenue recognition under ASC Topic 606 upon emergence. The new guidance requires us to recognize revenue upon transfer of goods or services to a customer at an amount that reflects the expected consideration to be received in exchange for those goods or services; and
|
•
|
We changed from a pass-through entity for tax purposes to a C Corporation and, accordingly, a taxable entity.
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon production levels which has an impact on oil prices;
|
•
|
social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;
|
•
|
weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;
|
•
|
the impact of the U.S. dollar exchange rates on commodity prices;
|
•
|
technological advances affecting energy consumption;
|
•
|
incur additional indebtedness;
|
•
|
incur additional liens;
|
•
|
pay dividends or make other distributions or repurchase or redeem our stock;
|
•
|
prepay, redeem, or repurchase certain of our indebtedness
|
•
|
make certain investments;
|
•
|
enter into certain transactions with our affiliates;
|
•
|
make certain capital expenditures;
|
•
|
consolidate, merge, sell, or otherwise dispose of certain of our assets;
|
•
|
enter into certain marketing activities for hydrocarbons;
|
•
|
create additional subsidiaries; and
|
•
|
amend or modify certain provisions of our organizational documents.
|
•
|
make distributions on, purchase or redeem the Company’s common stock or purchase or redeem subordinated indebtedness;
|
•
|
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and
|
•
|
adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.
|
•
|
the actual prices we receive for oil, natural gas and NGLs;
|
•
|
our actual development and production expenditures;
|
•
|
the amount and timing of actual production; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
our proved reserves;
|
•
|
the level of oil, natural gas and NGLs we are able to produce from existing wells;
|
•
|
the prices at which our oil, natural gas and NGLs are sold;
|
•
|
our ability to consummate planned asset divestitures;
|
•
|
the level of operating expenses; and
|
•
|
our ability to acquire, locate and produce new reserves.
|
•
|
the high cost, shortages or delivery delays of equipment and services;
|
•
|
shortages of or delays in obtaining water for hydraulic fracturing operations;
|
•
|
unexpected operational events and conditions;
|
•
|
adverse weather conditions;
|
•
|
human errors;
|
•
|
facility or equipment malfunctions;
|
•
|
title deficiencies that can render a lease worthless;
|
•
|
compliance with environmental and other governmental requirements;
|
•
|
unusual or unexpected geological formations;
|
•
|
loss of drilling fluid circulation;
|
•
|
formations with abnormal pressures;
|
•
|
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
|
•
|
fires;
|
•
|
blowouts, craterings and explosions;
|
•
|
uncontrollable flows of oil, natural gas or well fluids; and
|
•
|
pipeline capacity curtailments.
|
•
|
announcements concerning our competitors, the oil and gas industry or the economy in general;
|
•
|
fluctuations in the prices of oil, natural gas and NGLs;
|
•
|
general and industry-specific economic conditions;
|
•
|
changes in financial estimates or recommendations by securities analysts or failure to meet analysts’ performance expectations;
|
•
|
additions or departures of key members of management;
|
•
|
lack of trading liquidity;
|
•
|
any increased indebtedness we may incur in the future;
|
•
|
speculation or reports by the press or investment community with respect to us or our industry in general;
|
•
|
announcements by us or our competitors of significant contracts, acquisitions, dispositions, strategic partnerships, joint ventures or capital commitments;
|
•
|
changes or proposed changes in laws or regulations affecting the oil and gas industry or enforcement of these laws and regulations, or announcements relating to these matters; and
|
•
|
general market, political and economic conditions, including any such conditions and local conditions in the markets in which we operate.
|
•
|
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
|
•
|
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
|
•
|
limit the persons who may call special meetings of stockholders.
|
|
|
Successor
|
||||||
|
|
Common Stock
|
||||||
|
|
High
|
|
Low
|
||||
2017
|
|
|
|
|
||||
Fourth Quarter
|
|
$
|
21.00
|
|
|
$
|
18.25
|
|
Third Quarter (from September 28, 2017 through September 30, 2017)
|
|
$
|
20.50
|
|
|
$
|
17.04
|
|
|
|
Predecessor
|
||||||
|
|
Common Units
|
||||||
|
|
High
|
|
Low
|
||||
2017
|
|
|
|
|
||||
Third Quarter (from July 1, 2017 through July 31, 2017)
|
|
$
|
0.19
|
|
|
$
|
0.03
|
|
Second Quarter
|
|
$
|
0.09
|
|
|
$
|
0.03
|
|
First Quarter
|
|
$
|
1.11
|
|
|
$
|
0.06
|
|
2016
|
|
|
|
|
||||
Fourth Quarter
|
|
$
|
1.35
|
|
|
$
|
0.46
|
|
Third Quarter
|
|
$
|
2.09
|
|
|
$
|
0.86
|
|
Second Quarter
|
|
$
|
2.17
|
|
|
$
|
1.07
|
|
First Quarter
|
|
$
|
3.17
|
|
|
$
|
1.29
|
|
|
|
Cash Distributions
|
||||||
|
|
Per Unit
|
|
Record Date
|
|
Payment Date
|
||
2016
|
|
|
|
|
|
|
||
First Quarter
|
|
|
|
|
|
|
||
January
|
|
$
|
0.0300
|
|
|
March 1, 2016
|
|
March 15, 2016
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
|
Five Months Ended December 31, 2017
(4)
|
|
|
Seven
Months Ended
July 31,
2017
(4)
|
|
|
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
Year Ended December 31,
(3)
|
||||||||||||||||||||
|
|
|
|
|
2016
(4)
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil sales
|
|
$
|
72,557
|
|
|
|
$
|
97,496
|
|
|
$
|
169,955
|
|
|
$
|
164,111
|
|
|
$
|
268,685
|
|
|
$
|
268,922
|
|
Natural gas sales
|
|
96,236
|
|
|
|
113,587
|
|
|
174,263
|
|
|
193,496
|
|
|
285,439
|
|
|
124,513
|
|
||||||
NGLs sales
|
|
36,825
|
|
|
|
35,565
|
|
|
44,462
|
|
|
39,620
|
|
|
70,489
|
|
|
49,813
|
|
||||||
Oil, natural gas and NGLs sales
|
|
205,618
|
|
|
|
246,648
|
|
|
388,680
|
|
|
397,227
|
|
|
624,613
|
|
|
443,248
|
|
||||||
Net gains (losses) on commodity derivative contracts
|
|
(55,857
|
)
|
|
|
(24,887
|
)
|
|
(44,072
|
)
|
|
169,416
|
|
|
163,452
|
|
|
11,256
|
|
||||||
Total revenues and gains (losses) on derivatives
|
|
149,761
|
|
|
|
221,761
|
|
|
344,608
|
|
|
566,643
|
|
|
788,065
|
|
|
454,504
|
|
||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease operating expenses
|
|
60,976
|
|
|
|
87,092
|
|
|
159,672
|
|
|
146,654
|
|
|
132,515
|
|
|
105,502
|
|
||||||
Transportation, gathering, processing and compression
|
|
19,202
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Production and other taxes
|
|
13,145
|
|
|
|
21,186
|
|
|
38,637
|
|
|
40,576
|
|
|
61,874
|
|
|
40,430
|
|
||||||
Depreciation, depletion, amortization and accretion
|
|
71,321
|
|
|
|
58,384
|
|
|
149,790
|
|
|
247,119
|
|
|
226,937
|
|
|
167,535
|
|
Impairment of oil and natural gas properties
|
|
47,640
|
|
|
|
—
|
|
|
494,270
|
|
|
1,842,317
|
|
|
234,434
|
|
|
—
|
|
||||||
Impairment of goodwill
|
|
—
|
|
|
|
—
|
|
|
252,676
|
|
|
71,425
|
|
|
—
|
|
|
—
|
|
||||||
Exploration expense
|
|
1,365
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Selling, general and administrative expenses
(1)
|
|
21,658
|
|
|
|
28,810
|
|
|
51,518
|
|
|
55,076
|
|
|
30,839
|
|
|
25,942
|
|
||||||
Total costs and expenses
|
|
235,307
|
|
|
|
195,472
|
|
|
1,146,563
|
|
|
2,403,167
|
|
|
686,599
|
|
|
339,409
|
|
||||||
Income (loss) from operations
|
|
(85,546
|
)
|
|
|
26,289
|
|
|
(801,955
|
)
|
|
(1,836,524
|
)
|
|
101,466
|
|
|
115,095
|
|
||||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
|
(24,204
|
)
|
|
|
(35,276
|
)
|
|
(95,367
|
)
|
|
(87,573
|
)
|
|
(69,765
|
)
|
|
(61,148
|
)
|
||||||
Net gains (losses) on interest rate derivative contracts
|
|
—
|
|
|
|
30
|
|
|
(2,867
|
)
|
|
153
|
|
|
(1,933
|
)
|
|
(96
|
)
|
||||||
Net gain (loss) on acquisitions and divestiture of oil
and natural gas properties |
|
4,450
|
|
|
|
—
|
|
|
(4,979
|
)
|
|
40,533
|
|
|
34,523
|
|
|
5,591
|
|
||||||
Gain on extinguishment of debt
|
|
—
|
|
|
|
—
|
|
|
89,714
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Other
|
|
510
|
|
|
|
783
|
|
|
447
|
|
|
237
|
|
|
54
|
|
|
69
|
|
||||||
Total other expense
|
|
(19,244
|
)
|
|
|
(34,463
|
)
|
|
(13,052
|
)
|
|
(46,650
|
)
|
|
(37,121
|
)
|
|
(55,584
|
)
|
||||||
Loss before reorganization items
|
|
(104,790
|
)
|
|
|
(8,174
|
)
|
|
(815,007
|
)
|
|
(1,883,174
|
)
|
|
64,345
|
|
|
59,511
|
|
||||||
Reorganization items
|
|
(6,488
|
)
|
|
|
908,485
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net income (loss)
|
|
(111,278
|
)
|
|
|
900,311
|
|
|
(815,007
|
)
|
|
(1,883,174
|
)
|
|
64,345
|
|
|
59,511
|
|
||||||
Less: Net income attributable to non-controlling
interests |
|
(132
|
)
|
|
|
(13
|
)
|
|
(82
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net income (loss) attributable to Vanguard
stockholders/unitholders |
|
(111,410
|
)
|
|
|
900,298
|
|
|
(815,089
|
)
|
|
(1,883,174
|
)
|
|
64,345
|
|
|
59,511
|
|
||||||
Less: Distributions to Preferred unitholders
|
|
—
|
|
|
|
(2,230
|
)
|
|
(26,758
|
)
|
|
(26,759
|
)
|
|
(18,197
|
)
|
|
(2,634
|
)
|
||||||
Net income (loss) attributable to Common
stockholders/Common and Class B unitholders |
|
$
|
(111,410
|
)
|
|
|
$
|
898,068
|
|
|
$
|
(841,847
|
)
|
|
$
|
(1,909,933
|
)
|
|
$
|
46,148
|
|
|
$
|
56,877
|
|
Net Income (Loss) Per Share/Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Basic
|
|
$
|
(5.55
|
)
|
|
|
$
|
6.84
|
|
|
$
|
(6.41
|
)
|
|
$
|
(19.80
|
)
|
|
$
|
0.56
|
|
|
$
|
0.78
|
|
Diluted
|
|
$
|
(5.55
|
)
|
|
|
$
|
6.84
|
|
|
$
|
(6.41
|
)
|
|
$
|
(19.80
|
)
|
|
$
|
0.55
|
|
|
$
|
0.77
|
|
Distributions Declared Per Common and Class B Unit
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
0.06
|
|
|
$
|
1.42
|
|
|
$
|
2.52
|
|
|
$
|
2.46
|
|
Weighted Average Common Shares/Units
Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Basic
|
|
20,059
|
|
|
|
130,962
|
|
|
130,903
|
|
|
96,048
|
|
|
81,611
|
|
|
72,644
|
|
||||||
Diluted
|
|
20,059
|
|
|
|
130,962
|
|
|
130,903
|
|
|
96,048
|
|
|
82,039
|
|
|
72,992
|
|
||||||
Weighted Average Class B Units Outstanding
|
|
—
|
|
|
|
420
|
|
|
420
|
|
|
420
|
|
|
420
|
|
|
420
|
|
||||||
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
37,782
|
|
|
|
$
|
52,288
|
|
|
$
|
290,280
|
|
|
$
|
370,084
|
|
|
$
|
339,752
|
|
|
$
|
260,965
|
|
Net cash provided by (used in) investing activities
|
|
$
|
(29,526
|
)
|
|
|
$
|
76,836
|
|
|
$
|
206,822
|
|
|
$
|
(128,144
|
)
|
|
$
|
(1,446,202
|
)
|
|
$
|
(397,977
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
(33,104
|
)
|
|
|
$
|
(151,471
|
)
|
|
$
|
(447,145
|
)
|
|
$
|
(241,940
|
)
|
|
$
|
1,094,632
|
|
|
$
|
137,267
|
|
Other Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted EBITDA attributable to Vanguard
shareholders/unitholders
(2)
|
|
$
|
79,627
|
|
|
|
$
|
115,242
|
|
|
$
|
432,965
|
|
|
$
|
396,829
|
|
|
$
|
421,445
|
|
|
$
|
309,745
|
|
(1)
|
Includes $
0.1 million
,
$5.8 million
,
$10.2 million
,
$18.5 million
,
$11.7 million
and
$5.9 million
of non-cash unit-based compensation expense for the five months ended December 31, 2017 (Successor), seven months ended July 31, 2017 and in
2016
,
2015
,
2014
and
2013
(Predecessor), respectively.
|
(2)
|
See “—Non-GAAP Financial Measure” below.
|
(3)
|
From 2013 through 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets. The operating results of these properties were included with ours from the closing date of the acquisitions forward.
|
(4)
|
In 2017 and 2016, we completed the divestiture of oil and natural gas properties in the SCOOP/STACK area in Oklahoma and in our other operating areas. As such, there are no operating results from these properties included in our operating results from the closing date of the divestiture forward.
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
|
|
|
|
As of December 31,
|
||||||||||||||||
(in thousands)
|
|
As of December 31,
2017 |
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
2,762
|
|
|
|
$
|
49,957
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11,818
|
|
Short-term derivative assets
|
|
2,258
|
|
|
|
—
|
|
|
236,886
|
|
|
142,114
|
|
|
21,314
|
|
|||||
Other current assets
|
|
78,437
|
|
|
|
105,082
|
|
|
121,636
|
|
|
144,119
|
|
|
73,025
|
|
|||||
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment
|
|
1,533,392
|
|
|
|
858,253
|
|
|
1,721,976
|
|
|
2,975,806
|
|
|
1,810,517
|
|
|||||
Long-term derivative assets
|
|
—
|
|
|
|
—
|
|
|
80,161
|
|
|
83,583
|
|
|
60,474
|
|
|||||
Goodwill
(1)
|
|
—
|
|
|
|
253,370
|
|
|
506,046
|
|
|
420,955
|
|
|
420,955
|
|
|||||
Other assets
|
|
26,671
|
|
|
|
42,626
|
|
|
28,887
|
|
|
11,755
|
|
|
74,039
|
|
|||||
Total Assets
|
|
$
|
1,643,520
|
|
|
|
$
|
1,309,288
|
|
|
$
|
2,695,592
|
|
|
$
|
3,778,332
|
|
|
$
|
2,472,142
|
|
Short-term derivative liabilities
|
|
$
|
39,212
|
|
|
|
$
|
125
|
|
|
$
|
356
|
|
|
$
|
3,583
|
|
|
$
|
10,992
|
|
Long-term debt classified as current
(2)
|
|
—
|
|
|
|
1,753,345
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other current liabilities
|
|
120,872
|
|
|
|
135,213
|
|
|
201,652
|
|
|
175,021
|
|
|
114,411
|
|
|||||
Long-term debt
(2)
|
|
905,976
|
|
|
|
15,475
|
|
|
2,277,931
|
|
|
1,917,556
|
|
|
990,380
|
|
|||||
Long-term derivative liabilities
|
|
27,483
|
|
|
|
—
|
|
|
—
|
|
|
1,380
|
|
|
4,085
|
|
|||||
Other long-term liabilities
|
|
152,449
|
|
|
|
303,995
|
|
|
303,088
|
|
|
146,676
|
|
|
83,939
|
|
|||||
Stockholders'/Members’ equity (deficit)
|
|
397,528
|
|
|
|
(898,865
|
)
|
|
(87,435
|
)
|
|
1,534,116
|
|
|
1,268,335
|
|
|||||
Total Liabilities and Stockholders'/Members’ Equity
|
|
$
|
1,643,520
|
|
|
|
$
|
1,309,288
|
|
|
$
|
2,695,592
|
|
|
$
|
3,778,332
|
|
|
$
|
2,472,142
|
|
(1)
|
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Purchase completed on December 31, 2010 and the LRE Merger completed on October 5, 2015.
|
(2)
|
As a result of our Chapter 11 filing, we classified our debt under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 as current at December 31, 2016.
|
|
As of December 31, 2017
|
||
Reserve Data:
|
|
||
Estimated net proved reserves:
|
|
||
Crude oil (MMBbls)
|
39.0
|
|
|
Natural gas (Bcf)
|
1,357.6
|
|
|
NGLs (MMBbls)
|
38.4
|
|
|
Total (Bcfe)
|
1,821.5
|
|
|
Proved developed (Bcfe)
|
1,225.3
|
|
|
Proved undeveloped (Bcfe)
|
596.2
|
|
|
Proved developed reserves as % of total proved reserves
|
67
|
%
|
|
PV-10
(1)
|
$
|
1,194.8
|
|
Less: Future income taxes (discounted at 10%)
|
(121.2
|
)
|
|
Standardized Measure (in millions)
(2)
|
$
|
1,073.6
|
|
Representative Oil and Natural Gas Prices
(3)
:
|
|
||
Oil—WTI per Bbl
|
$
|
51.22
|
|
Natural gas—Henry Hub per MMBtu
|
$
|
2.99
|
|
NGLs—Volume-weighted average price per Bbl
|
$
|
19.24
|
|
(1)
|
PV-10 is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”, and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows.
|
(2)
|
Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the 12-month unweighted average of first-day-of-the-month price) and calculated net of the estimated future costs incurred in developing, producing and abandoning the proved reserves. Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Item 1. Business—Operations—Price Risk Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
|
(3)
|
Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month unweighted average of first-day-of-the-month commodity prices (the “12-month average price”) for January through December
2017
, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using the differentials to the crude oil 12-month average price per Bbl of
$51.22
.
|
|
|
Net Production
(1)
|
|
Average Realized Sales Prices
(2)
|
|
Production Cost
(3)
|
|||||||||||||||||||
|
|
Crude Oil
Bbls/day
|
|
Natural Gas Mcf/day
|
|
NGLs Bbls/day
|
|
Crude Oil
Per Bbl
|
|
Natural Gas
Per Mcf
|
|
NGLs
Per Bbl
|
|
Per Mcfe
|
|||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Pinedale (Green River Basin)
|
|
796
|
|
|
92,038
|
|
|
1,310
|
|
|
$
|
46.15
|
|
|
$
|
2.37
|
|
|
$
|
18.91
|
|
|
$
|
0.47
|
|
Mamm Creek (Piceance Basin)
|
|
535
|
|
|
45,704
|
|
|
3,676
|
|
|
$
|
41.47
|
|
|
$
|
2.27
|
|
|
$
|
14.16
|
|
|
$
|
0.56
|
|
All other fields
|
|
8,993
|
|
|
119,816
|
|
|
4,108
|
|
|
$
|
42.57
|
|
|
$
|
2.22
|
|
|
$
|
25.06
|
|
|
$
|
1.60
|
|
Total
|
|
10,324
|
|
|
257,558
|
|
|
9,094
|
|
|
$
|
42.38
|
|
|
$
|
2.28
|
|
|
$
|
19.77
|
|
|
$
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Pinedale (Green River Basin)
|
|
844
|
|
|
97,323
|
|
|
958
|
|
|
$
|
59.58
|
|
|
$
|
3.40
|
|
|
$
|
(1.72
|
)
|
|
$
|
0.44
|
|
Mamm Creek (Piceance Basin)
|
|
579
|
|
|
50,166
|
|
|
3,746
|
|
|
$
|
52.21
|
|
|
$
|
2.39
|
|
|
$
|
11.65
|
|
|
$
|
0.53
|
|
All other fields
|
|
11,308
|
|
|
147,885
|
|
|
5,449
|
|
|
$
|
53.34
|
|
|
$
|
2.85
|
|
|
$
|
16.86
|
|
|
$
|
1.40
|
|
Total
|
|
12,731
|
|
|
295,374
|
|
|
10,153
|
|
|
$
|
53.20
|
|
|
$
|
2.95
|
|
|
$
|
13.19
|
|
|
$
|
1.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Pinedale (Green River Basin)
|
|
804
|
|
|
98,266
|
|
|
1,932
|
|
|
$
|
58.87
|
|
|
$
|
2.37
|
|
|
$
|
0.26
|
|
|
$
|
0.54
|
|
Mamm Creek (Piceance Basin)
|
|
649
|
|
|
58,764
|
|
|
3,701
|
|
|
$
|
49.30
|
|
|
$
|
1.96
|
|
|
$
|
12.18
|
|
|
$
|
0.43
|
|
All other fields
|
|
9,529
|
|
|
135,066
|
|
|
3,927
|
|
|
$
|
57.24
|
|
|
$
|
2.07
|
|
|
$
|
21.71
|
|
|
$
|
1.41
|
|
Total
|
|
10,982
|
|
|
292,096
|
|
|
9,560
|
|
|
$
|
56.89
|
|
|
$
|
3.13
|
|
|
$
|
13.68
|
|
|
$
|
0.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Average daily production calculated based on 365 days for
2017
, 366 days for
2016
, and 365 days for
2015
, and includes production for all of our acquisitions from the closing dates of these acquisitions.
|
(2)
|
Average realized sales prices include the impact of hedges but exclude the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. The average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Management’s Discussion and Analysis of Financial Condition-
Year Ended December 31, 2017
compared to
Year Ended December 31, 2016
” and “Management’s Discussion and Analysis of Financial Condition -
Year Ended December 31, 2016
compared to
Year Ended December 31, 2015
” under Part II, Item 7 of this Annual Report.
|
(3)
|
Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).
|
•
|
Net interest expense;
|
•
|
Depreciation, depletion, amortization and accretion;
|
•
|
Impairment of oil and natural gas properties;
|
•
|
Impairment of goodwill;
|
•
|
Change in fair value of commodity derivative contracts;
|
•
|
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period;
|
•
|
Fair value of derivative contracts acquired that apply to contracts settled during the period;
|
•
|
Fair value of restructured derivative contracts;
|
•
|
Cash settlements paid on termination of derivative contracts;
|
•
|
Net gains or losses on interest rate derivative contracts;
|
•
|
Net gains and losses on acquisitions and divestiture of oil and natural gas properties;
|
•
|
Gain on extinguishment of debt;
|
•
|
Texas margin taxes;
|
•
|
Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers;
|
•
|
Reorganization and restructuring costs;
|
•
|
Material costs incurred on strategic transactions; and
|
•
|
Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard stockholders/unitholders.
|
Fair value of derivative contracts acquired that apply to contracts settled during the period
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(15,285
|
)
|
|
$
|
(44,761
|
)
|
|
$
|
(21,306
|
)
|
|
$
|
(30,200
|
)
|
Cash settlements paid on terminated derivative
contracts
(b)
|
|
$
|
(4,140
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fair value of restructured derivative contracts
(d)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
53,955
|
|
|
$
|
69,515
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net gains (losses) on commodity derivative contracts
|
|
$
|
(55,857
|
)
|
|
|
$
|
(24,887
|
)
|
|
$
|
(44,072
|
)
|
|
$
|
169,416
|
|
|
$
|
163,452
|
|
|
$
|
11,256
|
|
(b)
|
Adjusted EBITDA attributable to Vanguard shareholders for the five months ended December 31, 2017 excludes cash settlements paid on the terminated commodity derivative contracts covering future production from assets divested in 2017.
|
(d)
|
Adjusted EBITDA attributable to Vanguard unitholders for the year ended December 31, 2016 includes proceeds from the monetization of commodity derivative contracts of $54.0 million of which $37.1 million is attributable to derivative contracts that would have matured in 2017 and 2018. Excluding the proceeds attributable to the 2017 and 2018 commodity derivative contracts, Adjusted EBITDA available to Vanguard unitholders for the year ended December 31, 2016 amounted to $395.8 million.
|
•
|
the Green River Basin in Wyoming;
|
•
|
the Piceance Basin in Colorado;
|
•
|
the Permian Basin in West Texas and New Mexico;
|
•
|
the Arkoma Basin in Arkansas and Oklahoma;
|
•
|
the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;
|
•
|
the Big Horn Basin in Wyoming and Montana;
|
•
|
the Anadarko Basin in Oklahoma and North Texas;
|
•
|
the Wind River Basin in Wyoming; and
|
•
|
the Powder River Basin in Wyoming.
|
|
2018
|
2019
|
2020
|
2021
|
2022
|
2023
(1)
|
Oil ($/Bbl)
|
$60.33
|
$56.78
|
$54.08
|
$52.38
|
$51.66
|
$51.57
|
Gas ($/MMBtu)
|
$2.89
|
$2.83
|
$2.75
|
$2.78
|
$2.82
|
$2.86
|
|
Net Oil (Bbls)
|
Net Gas (MMcf)
|
Net NGL (Bbls)
|
Net Bcfe
|
Reserve Report at 4Q17
|
38,970
|
1,357,589
|
38,355
|
1,821.5
|
March 12, 2018 NYMEX Strip Price
|
39,071
|
1,344,733
|
38,132
|
1,808.0
|
% Difference
|
—%
|
(1)%
|
(1)%
|
(1)%
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
||||||||||
|
Five Months Ended
December 31, 2017 (1) |
|
|
Seven Months Ended
July 31, 2017
(1)
|
|
Years Ended December 31,
(1)
|
||||||||||||||
|
|
|
|
Combined
|
|
Predecessor
|
|
Predecessor
|
||||||||||||
|
|
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
72,557
|
|
|
|
$
|
97,496
|
|
|
$
|
170,053
|
|
|
$
|
169,955
|
|
|
$
|
164,111
|
|
Natural gas sales
|
96,236
|
|
|
|
113,587
|
|
|
209,823
|
|
|
174,263
|
|
|
193,496
|
|
|||||
Natural gas liquids sales
|
36,825
|
|
|
|
35,565
|
|
|
72,390
|
|
|
44,462
|
|
|
39,620
|
|
|||||
Oil, natural gas and NGLs sales
|
205,618
|
|
|
|
246,648
|
|
|
452,266
|
|
|
388,680
|
|
|
397,227
|
|
|||||
Net gains (losses) on commodity derivative contracts
|
(55,857
|
)
|
|
|
(24,887
|
)
|
|
(80,744
|
)
|
|
(44,072
|
)
|
|
169,416
|
|
|||||
Total revenues and gains (losses) on derivatives
|
$
|
149,761
|
|
|
|
$
|
221,761
|
|
|
$
|
371,522
|
|
|
$
|
344,608
|
|
|
$
|
566,643
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Lease operating expenses
|
60,976
|
|
|
|
87,092
|
|
|
148,068
|
|
|
159,672
|
|
|
146,654
|
|
|||||
Transportation, gathering, processing and compression
|
19,202
|
|
|
|
—
|
|
|
19,202
|
|
|
—
|
|
|
—
|
|
|||||
Production and other taxes
|
13,145
|
|
|
|
21,186
|
|
|
34,331
|
|
|
38,637
|
|
|
40,576
|
|
|||||
Depreciation, depletion, amortization and accretion
|
71,321
|
|
|
|
58,384
|
|
|
129,705
|
|
|
149,790
|
|
|
247,119
|
|
|||||
Impairment of oil and natural gas properties
|
47,640
|
|
|
|
—
|
|
|
47,640
|
|
|
494,270
|
|
|
1,842,317
|
|
|||||
Impairment of goodwill
|
—
|
|
|
|
—
|
|
|
—
|
|
|
252,676
|
|
|
71,425
|
|
|||||
Exploration expense
|
1,365
|
|
|
|
—
|
|
|
1,365
|
|
|
—
|
|
|
—
|
|
|||||
Selling, general and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Non-cash compensation
|
81
|
|
|
|
5,797
|
|
|
5,878
|
|
|
10,183
|
|
|
18,522
|
|
|||||
Other (excluding non-cash compensation)
|
21,577
|
|
|
|
23,013
|
|
|
44,590
|
|
|
41,335
|
|
|
36,554
|
|
|||||
Total costs and expenses
|
$
|
235,307
|
|
|
|
$
|
195,472
|
|
|
$
|
430,779
|
|
|
$
|
1,146,563
|
|
|
$
|
2,403,167
|
|
Other income and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
(24,204
|
)
|
|
|
$
|
(35,276
|
)
|
|
(59,480
|
)
|
|
$
|
(95,367
|
)
|
|
$
|
(87,573
|
)
|
|
Net gains (losses) on interest rate derivative contracts
|
$
|
—
|
|
|
|
$
|
30
|
|
|
30
|
|
|
$
|
(2,867
|
)
|
|
$
|
153
|
|
|
Net gain (loss) on acquisitions of oil and natural gas properties
|
$
|
4,450
|
|
|
|
$
|
—
|
|
|
4,450
|
|
|
$
|
(4,979
|
)
|
|
$
|
40,533
|
|
|
Gain on extinguishment of debt
|
$
|
—
|
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
89,714
|
|
|
$
|
—
|
|
|
Other
|
$
|
510
|
|
|
|
$
|
783
|
|
|
1,293
|
|
|
$
|
447
|
|
|
$
|
237
|
|
|
Reorganization items
|
$
|
(6,488
|
)
|
|
|
$
|
908,485
|
|
|
901,997
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
During 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward. During
|
|
|
Successor
(1)
|
|
|
Predecessor
(1)
|
|
Combined
|
|
Predecessor
(1)
|
||||||||
|
|
Five Months Ended
December 31, 2017 |
|
|
Seven Months Ended
July 31, 2017
|
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
||||||||
|
|
|
|
|
|
||||||||||||
Average realized prices, excluding hedging:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
47.79
|
|
|
|
$
|
43.33
|
|
|
$
|
45.13
|
|
|
$
|
36.47
|
|
Natural Gas (Price/Mcf)
|
|
$
|
2.49
|
|
|
|
$
|
2.05
|
|
|
$
|
2.23
|
|
|
$
|
1.61
|
|
NGLs (Price/Bbl)
|
|
$
|
27.70
|
|
|
|
$
|
17.87
|
|
|
$
|
21.81
|
|
|
$
|
11.97
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average realized prices, including hedging
(2)
:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
40.97
|
|
|
|
$
|
43.34
|
|
|
$
|
42.38
|
|
|
$
|
53.20
|
|
Natural Gas (Price/Mcf)
|
|
$
|
2.62
|
|
|
|
$
|
2.05
|
|
|
$
|
2.28
|
|
|
$
|
2.95
|
|
NGLs (Price/Bbl)
|
|
$
|
22.62
|
|
|
|
$
|
17.87
|
|
|
$
|
19.77
|
|
|
$
|
13.19
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
52.69
|
|
|
|
$
|
49.72
|
|
|
$
|
50.88
|
|
|
$
|
42.68
|
|
Natural Gas (Price/Mcf)
|
|
$
|
2.95
|
|
|
|
$
|
3.22
|
|
|
$
|
3.11
|
|
|
$
|
2.44
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total production volumes:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
|
1,518
|
|
|
|
2,250
|
|
|
3,768
|
|
|
4,660
|
|
||||
Natural Gas (MMcf)
|
|
38,634
|
|
|
|
55,375
|
|
|
94,009
|
|
|
108,107
|
|
||||
NGLs (MBbls)
|
|
1,329
|
|
|
|
1,990
|
|
|
3,319
|
|
|
3,716
|
|
||||
Combined (MMcfe)
|
|
55,719
|
|
|
|
80,814
|
|
|
136,533
|
|
|
158,359
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Bbls/day)
|
|
9,923
|
|
|
|
10,613
|
|
|
10,324
|
|
|
12,731
|
|
||||
Natural Gas (Mcf/day)
|
|
252,512
|
|
|
|
261,201
|
|
|
257,558
|
|
|
295,374
|
|
||||
NGLs (Bbls/day)
|
|
8,688
|
|
|
|
9,387
|
|
|
9,094
|
|
|
10,153
|
|
||||
Combined (Mcfe/day)
|
|
364,177
|
|
|
|
381,198
|
|
|
374,063
|
|
|
432,676
|
|
(1)
|
During
2017
and 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward. During
2016
, we also acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.
|
(2)
|
Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.
|
|
|
Year Ended
December 31,
(1)
|
|
Percentage
Increase
(Decrease)
|
|||||||
|
|
2016
|
|
2015
|
|
||||||
Average realized prices, excluding hedging:
|
|
|
|
|
|
|
|||||
Oil (Price/Bbl)
|
|
$
|
36.47
|
|
|
$
|
40.94
|
|
|
(11
|
)%
|
Natural Gas (Price/Mcf)
|
|
$
|
1.61
|
|
|
$
|
1.81
|
|
|
(11
|
)%
|
NGLs (Price/Bbl)
|
|
$
|
11.97
|
|
|
$
|
11.35
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|||||
Average realized prices, including hedging
(2)
:
|
|
|
|
|
|
|
|||||
Oil (Price/Bbl)
|
|
$
|
53.20
|
|
|
$
|
56.89
|
|
|
(6
|
)%
|
Natural Gas (Price/Mcf)
|
|
$
|
2.95
|
|
|
$
|
3.13
|
|
|
(6
|
)%
|
NGLs (Price/Bbl)
|
|
$
|
13.19
|
|
|
$
|
13.68
|
|
|
(4
|
)%
|
|
|
|
|
|
|
|
|||||
Average NYMEX prices:
|
|
|
|
|
|
|
|||||
Oil (Price/Bbl)
|
|
$
|
42.68
|
|
|
$
|
47.79
|
|
|
(11
|
)%
|
Natural Gas (Price/Mcf)
|
|
$
|
2.44
|
|
|
$
|
2.64
|
|
|
(8
|
)%
|
|
|
|
|
|
|
|
|||||
Total production volumes:
|
|
|
|
|
|
|
|||||
Oil (MBbls)
|
|
4,660
|
|
|
4,008
|
|
|
16
|
%
|
||
Natural Gas (MMcf)
|
|
108,107
|
|
|
106,615
|
|
|
1
|
%
|
||
NGLs (MBbls)
|
|
3,716
|
|
|
3,489
|
|
|
6
|
%
|
||
Combined (MMcfe)
|
|
158,359
|
|
|
151,600
|
|
|
4
|
%
|
||
|
|
|
|
|
|
|
|||||
Average daily production volumes:
|
|
|
|
|
|
|
|||||
Oil (Bbls/day)
|
|
12,731
|
|
|
10,982
|
|
|
16
|
%
|
||
Natural Gas (Mcf/day)
|
|
295,374
|
|
|
292,095
|
|
|
1
|
%
|
||
NGLs (Bbls/day)
|
|
10,153
|
|
|
9,560
|
|
|
6
|
%
|
||
Combined (Mcfe/day)
|
|
432,676
|
|
|
415,343
|
|
|
4
|
%
|
(1)
|
During
2016
and
2015
, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward.
|
(2)
|
Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.
|
•
|
We applied fresh-start accounting in accordance with ASC Topic 852,
Reorganizations
(“ASC Topic 852”), which resulted in our becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of our emergence from the Chapter 11 Cases on August 1, 2017. The fair values of our assets and liabilities differ materially from the recorded values of our assets and liabilities as reflected in our Predecessor’s historical consolidated balance sheets;
|
•
|
We changed our method of accounting for natural gas and oil properties from the full cost method of accounting to the successful efforts method of accounting;
|
•
|
We adopted the new standard for revenue recognition under ASC Topic 606 upon emergence. The new guidance requires us to recognize revenue upon transfer of goods or services to a customer at an amount that reflects the expected consideration to be received in exchange for those goods or services; and
|
•
|
We changed from a pass-through entity for tax purposes to a C corporation and, accordingly, a taxable entity;
|
|
Impairment Amount
(in thousands)
|
Natural Gas ($ per MMBtu)
|
Oil
($ per Bbl)
|
||
First quarter 2016
|
$
|
207,764
|
|
$2.41
|
$46.16
|
Second quarter 2016
|
$
|
157,894
|
|
$2.24
|
$42.91
|
Third quarter 2016
|
$
|
—
|
|
$2.29
|
$41.48
|
Fourth quarter 2016
|
$
|
128,612
|
|
$2.47
|
$42.60
|
Total
|
$
|
494,270
|
|
|
|
|
Impairment Amount
(in thousands)
|
Natural Gas ($ per MMBtu)
|
Oil
($ per Bbl)
|
||
First quarter 2015
|
$
|
132,610
|
|
$3.91
|
$82.62
|
Second quarter 2015
|
$
|
733,365
|
|
$3.44
|
$71.51
|
Third quarter 2015
|
$
|
491,487
|
|
$3.11
|
$59.23
|
Fourth quarter 2015
|
$
|
484,855
|
|
$2.62
|
$50.20
|
Total
|
$
|
1,842,317
|
|
|
|
|
Successor
|
||||||||||
|
Five Months Ended December 31, 2017
|
||||||||||
|
Under ASC 606
|
|
Under ASC 605
|
|
Increase
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
72,557
|
|
|
$
|
72,557
|
|
|
$
|
—
|
|
Natural gas sales
|
96,236
|
|
|
81,986
|
|
|
14,250
|
|
|||
NGLs sales
|
36,825
|
|
|
31,873
|
|
|
4,952
|
|
|||
Oil, natural gas and NGLs sales
|
205,618
|
|
|
186,416
|
|
|
19,202
|
|
|||
Net losses on commodity derivative contracts
|
(55,857
|
)
|
|
(55,857
|
)
|
|
—
|
|
|||
Total revenues and gains (losses) on derivatives
|
$
|
149,761
|
|
|
$
|
130,559
|
|
|
$
|
19,202
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Transportation, gathering, processing, and compression
|
$
|
19,202
|
|
|
$
|
—
|
|
|
$
|
19,202
|
|
Net loss
|
$
|
(111,278
|
)
|
|
$
|
(111,278
|
)
|
|
$
|
—
|
|
•
|
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 consolidated statements of operations.
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Five Months Ended
December 31, 2017 |
|
|
Seven Months Ended
July 31, 2017 |
|
Years Ended December 31,
|
||||||||||
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
2016
|
|
2015
|
||||||||||
Net cash provided by operating activities
|
|
$
|
37.8
|
|
|
|
$
|
52.3
|
|
|
$
|
290.3
|
|
|
$
|
370.1
|
|
Net cash provided by (used in) used in investing activities
|
|
$
|
(29.5
|
)
|
|
|
$
|
76.8
|
|
|
$
|
206.8
|
|
|
$
|
(128.1
|
)
|
Net cash used in financing activities
|
|
$
|
(33.1
|
)
|
|
|
$
|
(151.5
|
)
|
|
$
|
(447.1
|
)
|
|
$
|
(241.9
|
)
|
Year
|
|
Required Payments
|
||
2018
|
|
$
|
1,250
|
|
2019
|
|
1,250
|
|
|
2020
|
|
1,250
|
|
|
2021 through Maturity Dates
|
|
120,938
|
|
Year
|
|
Percentage
|
|
2020
|
|
106.75
|
%
|
2021
|
|
104.50
|
%
|
2022
|
|
102.25
|
%
|
2023 and thereafter
|
|
100.00
|
%
|
|
|
Payments Due by Year (in thousands)
|
||||||||||||||||||||||||||
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
Management base salaries
|
|
$
|
1,670
|
|
|
$
|
510
|
|
|
$
|
510
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,690
|
|
Asset retirement obligations
(1)
|
|
5,707
|
|
|
4,700
|
|
|
4,935
|
|
|
5,182
|
|
|
5,441
|
|
|
131,459
|
|
|
157,424
|
|
|||||||
Derivative liabilities
|
|
49,846
|
|
|
18,810
|
|
|
11,045
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79,701
|
|
|||||||
Successor Credit Facility
(2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
700,000
|
|
|
—
|
|
|
—
|
|
|
700,000
|
|
|||||||
Term Loan
(2)
|
|
1,250
|
|
|
1,250
|
|
|
1,250
|
|
|
120,938
|
|
|
—
|
|
|
—
|
|
|
124,688
|
|
|||||||
Senior Notes due 2024 and interest
|
|
7,265
|
|
|
7,265
|
|
|
7,265
|
|
|
7,265
|
|
|
7,265
|
|
|
92,205
|
|
|
128,530
|
|
|||||||
Operating leases
|
|
1,202
|
|
|
1,149
|
|
|
1,135
|
|
|
1,169
|
|
|
1,204
|
|
|
4,504
|
|
|
10,363
|
|
|||||||
Development commitments
(3)
|
|
25,274
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,274
|
|
|||||||
Firm transportation and processing agreements
(4)
|
|
1,009
|
|
|
820
|
|
|
410
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,239
|
|
|||||||
Lease Financing Obligations
(5)
|
|
5,442
|
|
|
5,442
|
|
|
4,359
|
|
|
1,278
|
|
|
—
|
|
|
—
|
|
|
16,521
|
|
|||||||
Other future obligations
|
|
468
|
|
|
308
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
776
|
|
|||||||
Total
|
|
$
|
99,133
|
|
|
$
|
40,254
|
|
|
$
|
30,909
|
|
|
$
|
835,832
|
|
|
$
|
13,910
|
|
|
$
|
228,168
|
|
|
$
|
1,248,206
|
|
(1)
|
Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Please read Note 9 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for additional information regarding our asset retirement obligations.
|
(2)
|
This table does not include interest to be paid on the principal balances shown as the interest rates on our financing arrangements are variable.
|
(3)
|
Represents authorized expenditures for drilling, completion, and major workover projects or recompletions.
|
(4)
|
Represents transportation demand charges. Please read Note 10 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report.
|
(5)
|
The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments. The amounts presented include interest payable for each year.
|
•
|
Fixed-price swaps -
where we will receive a fixed-price for our production and pay a variable market price to the contract counterparty.
|
•
|
Collars
- where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.
|
|
|
Year
2018
|
|
Year
2019
|
|
Year
2020
|
||||||
Gas Positions:
|
|
|
|
|
|
|
||||||
Fixed-Price Swaps:
|
|
|
|
|
|
|
||||||
Notional Volume (MMBtu)
|
|
70,242,000
|
|
|
52,539,000
|
|
|
47,227,500
|
|
|||
Fixed Price ($/MMBtu)
|
|
$
|
3.00
|
|
|
$
|
2.79
|
|
|
$
|
2.75
|
|
Collars:
|
|
|
|
|
|
|
||||||
Notional Volume (MMBtu)
|
|
—
|
|
|
4,125,000
|
|
|
5,490,000
|
|
|||
Floor Price ($/MMBtu)
|
|
$
|
—
|
|
|
$
|
2.60
|
|
|
$
|
2.60
|
|
Ceiling Price ($/MMBtu)
|
|
$
|
—
|
|
|
$
|
3.00
|
|
|
$
|
3.00
|
|
|
|
Year
2018
|
|
Year
2019
|
|
Year
2020
|
||||||
Oil Positions:
|
|
|
|
|
|
|
||||||
Fixed-Price Swaps (West Texas Intermediate):
|
|
|
|
|
|
|
||||||
Notional Volume (Bbls)
|
|
2,712,450
|
|
|
1,858,200
|
|
|
1,393,800
|
|
|||
Fixed Price ($/Bbl)
|
|
$
|
46.59
|
|
|
$
|
48.50
|
|
|
$
|
49.53
|
|
Collars:
|
|
|
|
|
|
|
||||||
Notional Volume (Bbls)
|
|
—
|
|
|
575,730
|
|
|
659,340
|
|
|||
Floor Price ($/Bbl)
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
44.17
|
|
Ceiling Price ($/Bbl)
|
|
$
|
—
|
|
|
$
|
54.04
|
|
|
$
|
55.00
|
|
|
|
Year
2018
|
||
NGLs Positions:
|
|
|
||
Fixed-Price Swaps:
|
|
|
||
Mont Belvieu Ethane
|
|
|
||
Notional Volume (Gallons)
|
|
9,198,000
|
|
|
Fixed Price ($/Gallon)
|
|
$
|
0.28
|
|
Mont Belvieu Propane
|
|
|
||
Notional Volume (Gallons)
|
|
22,995,000
|
|
|
Fixed Price ($/Bbl)
|
|
$
|
0.53
|
|
Mont Belvieu N. Butane
|
|
|
||
Notional Volume (Gallons)
|
|
7,665,000
|
|
|
Fixed Price ($/Gallon)
|
|
$
|
0.65
|
|
Mont Belvieu Isobutane
|
|
|
||
Notional Volume (Gallons)
|
|
6,132,000
|
|
|
Fixed Price ($/Gallon)
|
|
$
|
0.65
|
|
Mont Belvieu N. Gasoline
|
|
|
||
Notional Volume (Gallons)
|
|
10,731,000
|
|
|
Fixed Price ($/Gallon)
|
|
$
|
0.99
|
|
|
|
Current
Assets
|
|
Long-Term Assets
|
|
Current
Liabilities
|
|
Long-Term Liabilities
|
|
Total Amount Due From/(Owed To) Counterparty at
December 31, 2017
|
||||||||||
ABN AMRO Bank (A)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(25,816
|
)
|
|
$
|
(5,643
|
)
|
|
$
|
(31,459
|
)
|
Capital One (BBB+)
|
|
1,239
|
|
|
—
|
|
|
—
|
|
|
(5,234
|
)
|
|
(3,995
|
)
|
|||||
Citibank (A+)
|
|
—
|
|
|
—
|
|
|
(13,396
|
)
|
|
(4,574
|
)
|
|
(17,970
|
)
|
|||||
Huntington Bank (BBB+)
|
|
20
|
|
|
—
|
|
|
—
|
|
|
(9,384
|
)
|
|
(9,364
|
)
|
|||||
JP Morgan (A-)
|
|
999
|
|
|
—
|
|
|
—
|
|
|
(2,648
|
)
|
|
(1,649
|
)
|
|||||
Total
|
|
$
|
2,258
|
|
|
$
|
—
|
|
|
$
|
(39,212
|
)
|
|
$
|
(27,483
|
)
|
|
$
|
(64,437
|
)
|
|
|
|
Page
|
|
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
|
|
|
|
|
||
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
|
Years Ended December 31,
|
||||||||||
|
|
|
|
2016
|
|
2015
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
||||||||
Oil sales
|
$
|
72,557
|
|
|
|
$
|
97,496
|
|
|
$
|
169,955
|
|
|
$
|
164,111
|
|
Natural gas sales
|
96,236
|
|
|
|
113,587
|
|
|
174,263
|
|
|
193,496
|
|
||||
Natural gas liquids sales
|
36,825
|
|
|
|
35,565
|
|
|
44,462
|
|
|
39,620
|
|
||||
Oil, natural gas and NGLs sales
|
205,618
|
|
|
|
246,648
|
|
|
388,680
|
|
|
397,227
|
|
||||
Net gains (losses) on commodity derivative contracts
|
(55,857
|
)
|
|
|
(24,887
|
)
|
|
(44,072
|
)
|
|
169,416
|
|
||||
Total revenues and gains (losses) on derivatives
|
149,761
|
|
|
|
221,761
|
|
|
344,608
|
|
|
566,643
|
|
||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
||||||||
Production:
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
60,976
|
|
|
|
87,092
|
|
|
159,672
|
|
|
146,654
|
|
||||
Transportation, gathering, processing and compression
|
19,202
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Production and other taxes
|
13,145
|
|
|
|
21,186
|
|
|
38,637
|
|
|
40,576
|
|
||||
Depreciation, depletion, amortization and accretion
|
71,321
|
|
|
|
58,384
|
|
|
149,790
|
|
|
247,119
|
|
||||
Impairment of oil and natural gas properties
|
47,640
|
|
|
|
—
|
|
|
494,270
|
|
|
1,842,317
|
|
||||
Impairment of goodwill
|
—
|
|
|
|
—
|
|
|
252,676
|
|
|
71,425
|
|
||||
Exploration expense
|
1,365
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Selling, general and administrative expenses
|
21,658
|
|
|
|
28,810
|
|
|
51,518
|
|
|
55,076
|
|
||||
Total costs and expenses
|
235,307
|
|
|
|
195,472
|
|
|
1,146,563
|
|
|
2,403,167
|
|
||||
Income (loss) from operations
|
(85,546
|
)
|
|
|
26,289
|
|
|
(801,955
|
)
|
|
(1,836,524
|
)
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
(24,204
|
)
|
|
|
(35,276
|
)
|
|
(95,367
|
)
|
|
(87,573
|
)
|
||||
Net gains (losses) on interest rate derivative contracts
|
—
|
|
|
|
30
|
|
|
(2,867
|
)
|
|
153
|
|
||||
Net gain (loss) on acquisitions and divestiture of oil
and natural gas properties |
4,450
|
|
|
|
—
|
|
|
(4,979
|
)
|
|
40,533
|
|
||||
Gain on extinguishment of debt
|
—
|
|
|
|
—
|
|
|
89,714
|
|
|
—
|
|
||||
Other
|
510
|
|
|
|
783
|
|
|
447
|
|
|
237
|
|
||||
Total other expense
|
(19,244
|
)
|
|
|
(34,463
|
)
|
|
(13,052
|
)
|
|
(46,650
|
)
|
||||
Loss before reorganization items
|
(104,790
|
)
|
|
|
(8,174
|
)
|
|
(815,007
|
)
|
|
(1,883,174
|
)
|
||||
Reorganization items
|
(6,488
|
)
|
|
|
908,485
|
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
(111,278
|
)
|
|
|
900,311
|
|
|
(815,007
|
)
|
|
(1,883,174
|
)
|
||||
Less: Net income attributable to non-controlling
interests |
(132
|
)
|
|
|
(13
|
)
|
|
(82
|
)
|
|
—
|
|
||||
Net income (loss) attributable to Vanguard
stockholders/unitholders |
(111,410
|
)
|
|
|
900,298
|
|
|
(815,089
|
)
|
|
(1,883,174
|
)
|
||||
Less: Distributions to Preferred unitholders
|
—
|
|
|
|
(2,230
|
)
|
|
(26,758
|
)
|
|
(26,759
|
)
|
||||
Net income (loss) attributable to Common
stockholders/Common and Class B unitholders |
$
|
(111,410
|
)
|
|
|
$
|
898,068
|
|
|
$
|
(841,847
|
)
|
|
$
|
(1,909,933
|
)
|
Net income (loss) per Share/Unit:
|
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
$
|
(5.55
|
)
|
|
|
$
|
6.84
|
|
|
$
|
(6.41
|
)
|
|
$
|
(19.80
|
)
|
Weighted average shares/units outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Common shares/units – basic and diluted
|
20,059
|
|
|
|
130,962
|
|
|
130,903
|
|
|
96,048
|
|
||||
Class B units – basic and diluted
|
—
|
|
|
|
420
|
|
|
420
|
|
|
420
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
2017 |
|
|
December 31,
2016 |
||||
Assets
|
|
|
|
|
|
|
||
Current assets
|
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
2,762
|
|
|
|
$
|
49,957
|
|
Trade accounts receivable, net
|
67,248
|
|
|
|
97,138
|
|
||
Derivative assets
|
2,258
|
|
|
|
—
|
|
||
Restricted cash
|
7,255
|
|
|
|
—
|
|
||
Other currents assets
|
3,934
|
|
|
|
7,944
|
|
||
Total current assets
|
83,457
|
|
|
|
155,039
|
|
||
Oil and natural gas properties
|
|
|
|
|
||||
Proved properties
|
1,560,552
|
|
|
|
4,725,692
|
|
||
Unproved Properties
|
85,393
|
|
|
|
—
|
|
||
|
1,645,945
|
|
|
|
4,725,692
|
|
||
Accumulated depletion, amortization and impairment
|
(112,553
|
)
|
|
|
(3,867,439
|
)
|
||
Oil and natural gas properties evaluated, net – successful efforts method at
December 31, 2017 and full cost method at December 31, 2016
|
1,533,392
|
|
|
|
858,253
|
|
||
Other assets
|
|
|
|
|
||||
Goodwill
|
—
|
|
|
|
253,370
|
|
||
Other assets
|
26,671
|
|
|
|
42,626
|
|
||
Total assets
|
$
|
1,643,520
|
|
|
|
$
|
1,309,288
|
|
Liabilities and equity (deficit)
|
|
|
|
|
|
|||
Current liabilities
|
|
|
|
|
|
|||
Accounts payable:
|
|
|
|
|
||||
Trade
|
$
|
9,141
|
|
|
|
$
|
12,929
|
|
Affiliates
|
—
|
|
|
|
1,443
|
|
||
Accrued liabilities:
|
|
|
|
|
||||
Lease operating
|
13,560
|
|
|
|
14,909
|
|
||
Developmental capital
|
12,275
|
|
|
|
6,676
|
|
||
Interest
|
6,312
|
|
|
|
13,345
|
|
||
Production and other taxes
|
20,982
|
|
|
|
32,663
|
|
||
Other
|
9,005
|
|
|
|
5,416
|
|
||
Derivative liabilities
|
39,212
|
|
|
|
125
|
|
||
Oil and natural gas revenue payable
|
37,422
|
|
|
|
33,672
|
|
||
Long-term debt classified as current
|
—
|
|
|
|
1,753,345
|
|
||
Other current liabilities
|
12,175
|
|
|
|
14,160
|
|
||
Total current liabilities
|
160,084
|
|
|
|
1,888,683
|
|
||
Long-term debt
|
905,976
|
|
|
|
15,475
|
|
||
Derivative liabilities
|
27,483
|
|
|
|
—
|
|
||
Asset retirement obligations
|
151,717
|
|
|
|
264,552
|
|
||
Other long-term liabilities
|
732
|
|
|
|
39,443
|
|
||
Total liabilities
|
1,245,992
|
|
|
|
2,208,153
|
|
||
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
|
December 31, 2017
|
|
|
December 31, 2016
|
||||
Stockholders’ equity/members’ deficit (Note 11)
|
|
|
|
|
|
|
|
||
Predecessor Preferred units, no units issued or outstanding at December 31,
2017; 13,881,873 units issued and outstanding at December 31, 2016 |
|
—
|
|
|
|
335,444
|
|
||
Predecessor Common units, no units issued or outstanding at December 31,
2017; 131,008,670 units issued and outstanding at December 31, 2016 |
|
—
|
|
|
|
(1,248,767
|
)
|
||
Predecessor Class B units, no units issued or outstanding at December 31,
2017; 420,000 issued and outstanding at December 31, 2016 |
|
—
|
|
|
|
7,615
|
|
||
Successor common stock ($0.001 par value, 50,000,000 shares authorized
and 20,100,178 shares issued and outstanding at December 31, 2017; no shares authorized or issued at December 31, 2016 |
|
20
|
|
|
|
—
|
|
||
Successor additional paid-in capital
|
|
506,640
|
|
|
|
—
|
|
||
Successor accumulated deficit
|
|
(111,410
|
)
|
|
|
—
|
|
||
Total stockholders' equity/members’ deficit
|
|
395,250
|
|
|
|
(905,708
|
)
|
||
Non-controlling interest in subsidiary
|
|
2,278
|
|
|
|
6,843
|
|
||
Total stockholders' equity/members’ deficit
|
|
397,528
|
|
|
|
(898,865
|
)
|
||
Total liabilities and equity
|
|
$
|
1,643,520
|
|
|
|
$
|
1,309,288
|
|
(in thousands)
|
|
Cumulative Preferred Units
|
|
Common Units
|
|
Class B Units
|
|
Non-controlling Interest
|
|
Total Members’ Equity (Deficit)
|
||||||||||
Balance at January 1, 2015 (Predecessor)
|
|
$
|
335,444
|
|
|
$
|
1,191,057
|
|
|
$
|
7,615
|
|
|
$
|
—
|
|
|
$
|
1,534,116
|
|
Issuance of Common units as consideration for the Eagle Rock Merger, net of merger costs of $5,560
|
|
—
|
|
|
253,068
|
|
|
—
|
|
|
—
|
|
|
253,068
|
|
|||||
Issuance of Common units as consideration for the LRE Merger, net of merger costs of $3,961
|
|
—
|
|
|
119,315
|
|
|
—
|
|
|
—
|
|
|
119,315
|
|
|||||
Issuance of Common units, net of offering costs of $593
|
|
—
|
|
|
35,544
|
|
|
—
|
|
|
—
|
|
|
35,544
|
|
|||||
Repurchase of units under the common unit buyback program
|
|
—
|
|
|
(2,399
|
)
|
|
—
|
|
|
—
|
|
|
(2,399
|
)
|
|||||
Distributions to Preferred unitholders
|
|
—
|
|
|
(26,760
|
)
|
|
—
|
|
|
—
|
|
|
(26,760
|
)
|
|||||
Distributions to Common and Class B unitholders
|
|
—
|
|
|
(134,019
|
)
|
|
—
|
|
|
—
|
|
|
(134,019
|
)
|
|||||
Unit-based compensation
|
|
—
|
|
|
16,874
|
|
|
—
|
|
|
—
|
|
|
16,874
|
|
|||||
Net loss
|
|
—
|
|
|
(1,883,174
|
)
|
|
—
|
|
|
—
|
|
|
(1,883,174
|
)
|
|||||
Balance at December 31, 2015 (Predecessor)
|
|
335,444
|
|
|
(430,494
|
)
|
|
7,615
|
|
|
—
|
|
|
(87,435
|
)
|
|||||
Issuance costs related to prior period equity transactions
|
|
—
|
|
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
|||||
Distributions to Preferred unitholders
|
|
—
|
|
|
(5,575
|
)
|
|
—
|
|
|
—
|
|
|
(5,575
|
)
|
|||||
Distributions to Common and Class B unitholders
|
|
—
|
|
|
(7,998
|
)
|
|
—
|
|
|
—
|
|
|
(7,998
|
)
|
|||||
Unit-based compensation
|
|
—
|
|
|
10,639
|
|
|
—
|
|
|
—
|
|
|
10,639
|
|
|||||
Non-controlling interest in subsidiary
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,452
|
|
|
7,452
|
|
|||||
Net income (loss)
|
|
—
|
|
|
(815,089
|
)
|
|
—
|
|
|
82
|
|
|
(815,007
|
)
|
|||||
Potato Hills cash distribution to non-controlling interest
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(691
|
)
|
|
(691
|
)
|
|||||
Balance at December 31, 2016 (Predecessor)
|
|
335,444
|
|
|
(1,248,767
|
)
|
|
7,615
|
|
|
6,843
|
|
|
(898,865
|
)
|
|||||
Issuance costs related to prior period equity transactions
|
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|||||
Unit-based compensation
|
|
—
|
|
|
5,391
|
|
|
—
|
|
|
—
|
|
|
5,391
|
|
|||||
Net income
|
|
—
|
|
|
900,298
|
|
|
—
|
|
|
13
|
|
|
900,311
|
|
|||||
Potato Hills cash distribution to non-controlling interest
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(235
|
)
|
|
(235
|
)
|
|||||
Balance at July 31, 2017 (Predecessor)
|
|
$
|
335,444
|
|
|
$
|
(343,059
|
)
|
|
$
|
7,615
|
|
|
$
|
6,621
|
|
|
$
|
6,621
|
|
Cancellation of Predecessor equity
|
|
(335,444
|
)
|
|
343,059
|
|
|
(7,615
|
)
|
|
(4,347
|
)
|
|
(4,347
|
)
|
|||||
Balance at July 31, 2017 (Predecessor)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,274
|
|
|
$
|
2,274
|
|
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|||||||||||||
(in thousands, except per share amounts)
|
|
Shares
|
|
Amount
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Non- controlling Interest
|
|
Total Stockholders' Equity
|
|||||||||||
Issuance of Successor common stock and
warrants |
|
20,056
|
|
|
$
|
20
|
|
|
$
|
506,923
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
506,943
|
|
Balance at July 31, 2017 (Successor)
|
|
20,056
|
|
|
20
|
|
|
506,923
|
|
|
—
|
|
|
2,274
|
|
|
509,217
|
|
|||||
Net income (loss)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(111,410
|
)
|
|
132
|
|
|
(111,278
|
)
|
|||||
Exercise of warrants
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|||||
Issuance of common shares for settlement of general
unsecured claims
|
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Offering costs
|
|
—
|
|
|
—
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
(376
|
)
|
|||||
Share-based compensation
|
|
—
|
|
|
—
|
|
|
81
|
|
|
—
|
|
|
—
|
|
|
81
|
|
|||||
Potato Hills cash distribution to non-controlling interest
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(128
|
)
|
|
(128
|
)
|
|||||
Balance at December 31, 2017 (Successor)
|
|
20,100
|
|
|
$
|
20
|
|
|
$
|
506,640
|
|
|
$
|
(111,410
|
)
|
|
$
|
2,278
|
|
|
$
|
397,528
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
(in thousands)
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31,
2017
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net income (loss)
|
$
|
(111,278
|
)
|
|
|
$
|
900,311
|
|
|
$
|
(815,007
|
)
|
|
$
|
(1,883,174
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
||||||
Depreciation, depletion, amortization and accretion
|
71,321
|
|
|
|
58,384
|
|
|
149,790
|
|
|
247,119
|
|
||||
Impairment of oil and natural gas properties
|
47,640
|
|
|
|
—
|
|
|
494,270
|
|
|
1,842,317
|
|
||||
Impairment of goodwill
|
—
|
|
|
|
—
|
|
|
252,676
|
|
|
71,425
|
|
||||
Amortization of deferred financing costs
|
1,117
|
|
|
|
2,584
|
|
|
4,565
|
|
|
4,206
|
|
||||
Amortization of debt discount
|
—
|
|
|
|
348
|
|
|
3,746
|
|
|
1,071
|
|
||||
Reorganization cost
|
—
|
|
|
|
(937,956
|
)
|
|
—
|
|
|
—
|
|
||||
Compensation related items
|
81
|
|
|
|
5,429
|
|
|
10,639
|
|
|
16,874
|
|
||||
Post Eagle Rock Merger severance costs
|
—
|
|
|
|
—
|
|
|
—
|
|
|
13,955
|
|
||||
Net (gains) losses on commodity and interest rate derivative contracts
|
55,857
|
|
|
|
24,858
|
|
|
46,939
|
|
|
(169,569
|
)
|
||||
Net cash settlements received (paid) on matured commodity derivative contracts
|
(12,174
|
)
|
|
|
7
|
|
|
226,876
|
|
|
211,723
|
|
||||
Net cash settlements paid on matured interest rate derivative contracts
|
—
|
|
|
|
(95
|
)
|
|
(13,398
|
)
|
|
(5,227
|
)
|
||||
Cash received on termination of derivative contracts
|
(4,140
|
)
|
|
|
—
|
|
|
53,955
|
|
|
40,998
|
|
||||
Net (gain) loss on acquisitions and divestiture of oil and natural gas properties
|
(4,450
|
)
|
|
|
—
|
|
|
4,979
|
|
|
(40,533
|
)
|
||||
Gain on extinguishment of debt
|
—
|
|
|
|
—
|
|
|
(89,714
|
)
|
|
—
|
|
||||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Trade accounts receivable
|
(11,381
|
)
|
|
|
34,845
|
|
|
9,559
|
|
|
53,423
|
|
||||
Payables to affiliates
|
—
|
|
|
|
(895
|
)
|
|
(314
|
)
|
|
934
|
|
||||
Premiums paid on commodity derivative contracts
|
—
|
|
|
|
(16
|
)
|
|
(430
|
)
|
|
(4,235
|
)
|
||||
Restricted cash
|
—
|
|
|
|
(28,455
|
)
|
|
—
|
|
|
—
|
|
||||
Other current assets
|
552
|
|
|
|
1,435
|
|
|
(3,050
|
)
|
|
(1,615
|
)
|
||||
Accounts payable and oil and natural gas revenue payable
|
(138
|
)
|
|
|
19,444
|
|
|
(17,954
|
)
|
|
(555
|
)
|
||||
Accrued expenses and other current liabilities
|
3,830
|
|
|
|
(27,018
|
)
|
|
(41,582
|
)
|
|
(43,320
|
)
|
||||
Other assets
|
945
|
|
|
|
(922
|
)
|
|
13,735
|
|
|
14,267
|
|
||||
Net cash provided by operating activities
|
37,782
|
|
|
|
52,288
|
|
|
290,280
|
|
|
370,084
|
|
||||
Investing activities
|
|
|
|
|
|
|
|
|
|
|||||||
Additions to property and equipment
|
(4
|
)
|
|
|
(102
|
)
|
|
(101
|
)
|
|
(644
|
)
|
||||
Potato Hills Gas Gathering System acquisition
|
—
|
|
|
|
—
|
|
|
(7,501
|
)
|
|
—
|
|
||||
Additions to oil and natural gas properties
|
(34,675
|
)
|
|
|
(25,694
|
)
|
|
(64,537
|
)
|
|
(112,639
|
)
|
||||
Acquisitions of oil and natural gas properties and derivative contracts
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(12,970
|
)
|
||||
Cash acquired in the LRE and Eagle Rock Mergers
|
—
|
|
|
|
—
|
|
|
—
|
|
|
18,503
|
|
||||
Proceeds from the sale of oil and natural gas properties
|
36,109
|
|
|
|
126,363
|
|
|
298,701
|
|
|
1,777
|
|
||||
Deposits and prepayments of oil and natural gas properties
|
(30,956
|
)
|
|
|
(23,731
|
)
|
|
(19,740
|
)
|
|
(22,171
|
)
|
||||
Net cash provided by (used in) investing activities
|
(29,526
|
)
|
|
|
76,836
|
|
|
206,822
|
|
|
(128,144
|
)
|
||||
Financing activities
|
|
|
|
|
|
|
|
|
||||||||
Proceeds from long-term debt
|
9,821
|
|
|
|
—
|
|
|
93,500
|
|
|
420,000
|
|
||||
Repayment of debt
|
(42,118
|
)
|
|
|
(41,603
|
)
|
|
(517,157
|
)
|
|
(508,617
|
)
|
||||
Proceeds from Term Loan borrowings
|
—
|
|
|
|
125,000
|
|
|
—
|
|
|
—
|
|
||||
Repayment of debt under the predecessor credit facility
|
—
|
|
|
|
(500,266
|
)
|
|
—
|
|
|
—
|
|
||||
Proceeds from common unit offerings, net
|
—
|
|
|
|
—
|
|
|
—
|
|
|
35,544
|
|
||||
Proceeds from rights offerings and second lien investment
|
—
|
|
|
|
275,000
|
|
|
—
|
|
|
—
|
|
||||
Exercise of warrants
|
12
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Repurchase of units under the common unit buyback program
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(2,399
|
)
|
||||
Distributions to Preferred unitholders
|
—
|
|
|
|
—
|
|
|
(6,690
|
)
|
|
(26,760
|
)
|
||||
Distributions to Common and Class B members
|
—
|
|
|
|
—
|
|
|
(11,902
|
)
|
|
(147,641
|
)
|
||||
Potato Hills distribution to non-controlling interest
|
(128
|
)
|
|
|
(235
|
)
|
|
(691
|
)
|
|
—
|
|
||||
Financing fees
|
(691
|
)
|
|
|
(9,367
|
)
|
|
(4,205
|
)
|
|
(12,067
|
)
|
||||
Net cash used in financing activities
|
(33,104
|
)
|
|
|
(151,471
|
)
|
|
(447,145
|
)
|
|
(241,940
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31,
2017
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Net increase (decrease) in cash and cash equivalents
|
(24,848
|
)
|
|
|
(22,347
|
)
|
|
49,957
|
|
|
—
|
|
||||
Cash and cash equivalents,
beginning of period
|
27,610
|
|
|
|
49,957
|
|
|
—
|
|
|
—
|
|
||||
Cash and cash equivalents,
end of period
|
$
|
2,762
|
|
|
|
$
|
27,610
|
|
|
$
|
49,957
|
|
|
$
|
—
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
||||||
Cash paid for interest
|
$
|
16,763
|
|
|
|
$
|
29,631
|
|
|
$
|
85,371
|
|
|
$
|
83,557
|
|
Non-cash financing and investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Asset retirement obligations
|
$
|
14,158
|
|
|
|
$
|
9,581
|
|
|
$
|
8,935
|
|
|
$
|
24,766
|
|
LRE and Eagle Rock Mergers
|
|
|
|
|
|
|
|
|
||||||||
Assets acquired:
|
|
|
|
|
|
|
|
|
||||||||
Accounts receivable and other current assets
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,201
|
|
Net derivative assets
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
166,758
|
|
Oil and natural gas properties
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
672,178
|
|
Other long-term assets
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10,001
|
|
Liabilities assumed:
|
|
|
|
|
|
|
|
|
||||||||
Accounts payable and other current liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
70,085
|
|
Asset retirement obligations
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
88,228
|
|
Long-term debt
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
446,550
|
|
Other long-term liabilities
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
40,571
|
|
Common units issued in the LRE and Eagle Rock Mergers
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
381,904
|
|
•
|
the Green River Basin in Wyoming;
|
•
|
the Permian Basin in West Texas and New Mexico;
|
•
|
the Piceance Basin in Colorado;
|
•
|
the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;
|
•
|
the Arkoma Basin in Arkansas and Oklahoma;
|
•
|
the Big Horn Basin in Wyoming and Montana;
|
•
|
the Anadarko Basin in Oklahoma and North Texas;
|
•
|
the Wind River Basin in Wyoming; and
|
•
|
the Powder River Basin in Wyoming.
|
(a)
|
Basis of Presentation and Principles of Consolidation:
|
(b)
|
Emergence from Voluntary Reorganization under Chapter 11:
|
(c)
|
New Pronouncements Recently Adopted:
|
(d)
|
New Pronouncements Issued But Not Yet Adopted:
|
(e)
|
Cash Equivalents:
|
(f)
|
Accounts Receivable and Allowance for Doubtful Accounts:
|
(g)
|
Inventory:
|
(h)
|
Oil and Natural Gas Properties - Transition from Full Cost Method to Successful Efforts Accounting Method:
|
|
Impairment Amount
(in thousands)
|
Natural Gas ($ per MMBtu)
|
Oil
($ per Bbl)
|
||
First quarter 2016
|
$
|
207,764
|
|
$2.41
|
$46.16
|
Second quarter 2016
|
$
|
157,894
|
|
$2.24
|
$42.91
|
Third quarter 2016
|
$
|
—
|
|
$2.29
|
$41.48
|
Fourth quarter 2016
|
$
|
128,612
|
|
$2.47
|
$42.60
|
Total
|
$
|
494,270
|
|
|
|
|
Impairment Amount
(in thousands)
|
Natural Gas ($ per MMBtu)
|
Oil
($ per Bbl)
|
||
First quarter 2015
|
$
|
132,610
|
|
$3.91
|
$82.62
|
Second quarter 2015
|
$
|
733,365
|
|
$3.44
|
$71.51
|
Third quarter 2015
|
$
|
491,487
|
|
$3.11
|
$59.23
|
Fourth quarter 2015
|
$
|
484,855
|
|
$2.62
|
$50.20
|
Total
|
$
|
1,842,317
|
|
|
|
(i)
|
Goodwill and Other Intangible Assets:
|
(j)
|
Asset Retirement Obligations:
|
(k)
|
Revenue Recognition and Gas Imbalances:
|
(l)
|
Concentrations of Credit Risk:
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips
|
|
14%
|
|
|
13%
|
|
11%
|
|
7%
|
Mieco, Inc.
|
|
12%
|
|
|
11%
|
|
12%
|
|
20%
|
(m)
|
Use of Estimates:
|
(n)
|
Price and Interest Rate Risk Management Activities:
|
•
|
Fixed-price swaps -
where we receive a fixed-price for our production and pay a variable market price to the contract counterparty.
|
•
|
Collars
- where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.
|
(o)
|
Income Taxes:
|
(p)
|
Prior Year Financial Statement Presentation:
|
•
|
The Predecessor transferred all of its membership interests in VNG, a Kentucky limited liability company and the Predecessor’s wholly owned first-tier subsidiary, to the Successor (formerly known as VNR Finance Corp.). VNG directly or indirectly owned all of the other subsidiaries of the Predecessor. As a result of the foregoing and certain other transactions, the Successor is no longer a subsidiary of the Predecessor and now owns all of the former subsidiaries of the Predecessor;
|
•
|
VNG, as borrower, entered into the Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an
$850.0 million
exit senior secured reserve-based revolving credit facility (the “Revolving Loan”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date was
$850.0 million
and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was
$730.0 million
. The Successor Credit Facility also includes an additional
$125.0 million
senior secured term loan (the “Term Loan”). The holders of claims under the Predecessor Credit Facility received a recovery, consisting of a cash pay down and their pro rata share of the Successor Credit Facility. The next borrowing base redetermination is scheduled for August of 2018;
|
•
|
The Successor issued approximately
$80.7 million
aggregate principal amount of new
9.0%
Senior Secured Second Lien Notes due 2024 (the “New Notes” or “Senior Notes due 2024”) to certain eligible holders of their outstanding Old Second Lien Notes in full satisfaction of their claim of approximately
$80.7 million
related to the Old Second Lien Notes held by such holders;
|
•
|
The Predecessor’s Senior Notes were cancelled and the holders of the Senior Notes received their pro rata share of
97%
(subject to dilution by the other transactions referred to in this section) of the Common Stock, in full and final satisfaction of their claims;
|
•
|
The Predecessor completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated
$275.0 million
of gross proceeds. The rights offering resulted in subscriptions for
18.1
million shares of Successor common stock, representing approximately
89.92%
of outstanding shares of Common Stock, to holders of claims arising under the Senior Notes and to the Backstop Parties;
|
•
|
The Successor entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain recipients of shares of its Common Stock distributed on the Effective Date that were parties to the Amended and Restated Backstop Commitment Agreement (including the Backstop Parties and certain of their affiliates and related funds), in accordance with the terms set forth in the Final Plan (collectively, the “Registration Rights Holders”). Pursuant to the Registration Rights Agreement, we agreed to, among other things, file a registration statement with the SEC within 90 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined in the Registration Rights Agreement). We filed the registration statement on October 30, 2017;
|
•
|
Additional shares of Common Stock, representing
10%
of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);
|
•
|
All outstanding Preferred Units (defined below) issued and outstanding immediately prior to the Effective Date were canceled and the holders thereof received their pro rata shares of (i)
3%
(subject to dilution by the other transactions
|
•
|
All common equity of the Predecessor issued and outstanding immediately prior to the Effective Date was cancelled and the holders of the common equity received Common Unit Warrants (as defined below), in full and final satisfaction of their interests;
|
•
|
The Successor entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Successor 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 the Common Stock as of the Effective Date; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which are exercisable to purchase up to
640,876
shares of the Common Stock as of the Effective Date. The expiration date of the Warrants is February 1, 2021. The strike price for the Preferred Unit Warrants is
$44.25
, and the strike price for the Common Unit Warrants is
$61.45
;
|
•
|
By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. A new board was established for the Successor Company;
|
•
|
Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders; and
|
•
|
The Successor issued
20.1 million
shares of common stock,
$0.001
par value.
|
|
July 31, 2017
|
||
Enterprise Value
|
$
|
1,425,000
|
|
Plus: Cash and cash equivalents
|
27,610
|
|
|
Less: Debt
|
(943,393
|
)
|
|
Total stockholders' equity
|
509,217
|
|
|
Less: Fair value of warrants
|
(11,734
|
)
|
|
Less: Fair value of non-controlling interest
|
(2,274
|
)
|
|
Fair Value of Successor common stock
|
$
|
495,209
|
|
|
July 31, 2017
|
||
Successor Credit Facility
|
$
|
730,000
|
|
Successor Term Loan
|
125,000
|
|
|
Senior Notes due 2024
|
80,722
|
|
|
Lease Financing Obligation, net of current portion
|
12,464
|
|
|
Current portion of Lease Financing Obligation
|
4,647
|
|
|
Total Fair value of debt
|
952,833
|
|
|
Successor Credit Facility fees and debt issuance costs
|
(9,440
|
)
|
|
Total Debt
|
$
|
943,393
|
|
|
July 31, 2017
|
||
Enterprise Value
|
$
|
1,425,000
|
|
Plus: Cash and cash equivalents
|
27,610
|
|
|
Plus: Current liabilities, excluding current portion of Lease Financing Obligation
|
147,552
|
|
|
Plus: Other noncurrent liabilities
|
15,589
|
|
|
Plus: Long-term asset retirement obligation
|
136,769
|
|
|
Reorganization Value of Successor assets
|
$
|
1,752,520
|
|
|
|
As of July 31, 2017
|
||||||||||||||||
(in thousands)
|
|
Predecessor
|
|
Reorganization Adjustments
(1)
|
|
|
Fresh-Start Adjustments
|
|
|
Successor
|
||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||
Current assets
|
|
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
|
$
|
68,933
|
|
|
$
|
(41,323
|
)
|
(2)
|
|
$
|
—
|
|
|
|
$
|
27,610
|
|
Trade accounts receivable, net
|
|
64,253
|
|
|
(155
|
)
|
(3)
|
|
(8,231
|
)
|
(15)
|
|
55,867
|
|
||||
Derivative assets
|
|
3,236
|
|
|
—
|
|
|
|
—
|
|
|
|
3,236
|
|
||||
Restricted cash
|
|
102,556
|
|
|
(74,101
|
)
|
(4)
|
|
—
|
|
|
|
28,455
|
|
||||
Other current assets
|
|
4,430
|
|
|
(394
|
)
|
(5)
|
|
416
|
|
(16)
|
|
4,452
|
|
||||
Total current assets
|
|
243,408
|
|
|
(115,973
|
)
|
|
|
(7,815
|
)
|
|
|
119,620
|
|
||||
Oil and natural gas properties, at cost
|
|
4,635,867
|
|
|
—
|
|
|
|
(3,029,173
|
)
|
(17)
|
|
1,606,694
|
|
||||
Accumulated depletion
|
|
(3,916,889
|
)
|
|
—
|
|
|
|
3,916,889
|
|
(17)
|
|
—
|
|
||||
Oil and natural gas properties
|
|
718,978
|
|
|
—
|
|
|
|
887,716
|
|
|
|
1,606,694
|
|
||||
Other assets
|
|
|
|
|
|
|
|
|
|
|
||||||||
Goodwill
|
|
253,370
|
|
|
—
|
|
|
|
(253,370
|
)
|
(18)
|
|
—
|
|
||||
Other assets
|
|
44,315
|
|
|
—
|
|
|
|
(18,109
|
)
|
(19)(20)
|
|
26,206
|
|
||||
Total assets
|
|
$
|
1,260,071
|
|
|
$
|
(115,973
|
)
|
|
|
$
|
608,422
|
|
|
|
$
|
1,752,520
|
|
Liabilities and equity (deficit)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
||||||||
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Trade
|
|
$
|
8,444
|
|
|
$
|
9,978
|
|
(6)
|
|
$
|
—
|
|
|
|
$
|
18,422
|
|
Accrued liabilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Lease operating
|
|
13,199
|
|
|
—
|
|
|
|
—
|
|
|
|
13,199
|
|
||||
Development capital
|
|
8,928
|
|
|
—
|
|
|
|
—
|
|
|
|
8,928
|
|
||||
Interest
|
|
8,478
|
|
|
(8,478
|
)
|
(7)
|
|
—
|
|
|
|
—
|
|
||||
Production and other taxes
|
|
23,494
|
|
|
—
|
|
|
|
—
|
|
|
|
23,494
|
|
||||
Other
|
|
20,933
|
|
|
12,297
|
|
(8)
|
|
—
|
|
|
|
33,230
|
|
||||
Derivative liabilities
|
|
12,987
|
|
|
—
|
|
|
|
—
|
|
|
|
12,987
|
|
||||
Oil and natural gas revenue payable
|
|
36,087
|
|
|
—
|
|
|
|
(7,808
|
)
|
(15)
|
|
28,279
|
|
||||
Long-term debt classified as current
|
|
1,300,971
|
|
|
(1,300,971
|
)
|
(9)
|
|
—
|
|
|
|
—
|
|
||||
Other
|
|
14,246
|
|
|
(382
|
)
|
(10)
|
|
(203
|
)
|
(21)
|
|
13,661
|
|
||||
Total current liabilities
|
|
1,447,767
|
|
|
(1,287,556
|
)
|
|
|
(8,011
|
)
|
|
|
152,200
|
|
||||
Long-term debt, net of current portion
|
|
12,647
|
|
|
926,281
|
|
(11)
|
|
(183
|
)
|
(22)
|
|
938,745
|
|
||||
Derivative liabilities
|
|
15,143
|
|
|
—
|
|
|
|
—
|
|
|
|
15,143
|
|
||||
Asset retirement obligations, net of current portion
|
|
260,089
|
|
|
—
|
|
|
|
(123,320
|
)
|
(23)
|
|
136,769
|
|
||||
Other long-term liabilities
|
|
37,683
|
|
|
—
|
|
|
|
(37,237
|
)
|
(24)
|
|
446
|
|
||||
Total liabilities not subject to compromise
|
|
1,773,329
|
|
|
(361,275
|
)
|
|
|
(168,751
|
)
|
|
|
1,243,303
|
|
||||
Liabilities subject to compromise
|
|
479,911
|
|
|
(479,911
|
)
|
(12)
|
|
—
|
|
|
|
—
|
|
||||
Total Liabilities
|
|
2,253,240
|
|
|
(841,186
|
)
|
|
|
(168,751
|
)
|
|
|
1,243,303
|
|
|
|
As of July 31, 2017
|
||||||||||||||||
|
|
Predecessor
|
|
Reorganization Adjustments
(1)
|
|
|
Fresh-Start Adjustments
|
|
|
Successor
|
||||||||
Stockholders’ equity/Members’ (deficit) (Note 9)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Preferred units (Predecessor)
|
|
335,444
|
|
|
(335,444
|
)
|
(13)
|
|
—
|
|
|
|
—
|
|
||||
Common units (Predecessor)
|
|
(1,342,849
|
)
|
|
763,217
|
|
(13)
|
|
579,632
|
|
(25)
|
|
—
|
|
||||
Class B units (Predecessor)
|
|
7,615
|
|
|
(7,615
|
)
|
(13)
|
|
—
|
|
|
|
—
|
|
||||
Common stock (Successor)
|
|
—
|
|
|
20
|
|
(14)
|
|
—
|
|
|
|
20
|
|
||||
Additional paid-in capital (Successor)
|
|
—
|
|
|
305,035
|
|
(14)
|
|
201,888
|
|
(25)
|
|
506,923
|
|
||||
Total VNR stockholders' equity/ members’ (deficit)
|
|
(999,790
|
)
|
|
725,213
|
|
|
|
781,520
|
|
|
|
506,943
|
|
||||
Non-controlling interest in subsidiary
|
|
6,621
|
|
|
—
|
|
|
|
(4,347
|
)
|
(26)
|
|
2,274
|
|
||||
Total stockholders' equity/members’ (deficit)
|
|
(993,169
|
)
|
|
725,213
|
|
|
|
777,173
|
|
|
|
509,217
|
|
||||
Total liabilities and equity (deficit)
|
|
$
|
1,260,071
|
|
|
$
|
(115,973
|
)
|
|
|
$
|
608,422
|
|
|
|
$
|
1,752,520
|
|
1)
|
Represent amounts recorded as of the Convenience Date for the implementation of the Final Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s common stock and equity warrants, proceeds received from the Successor’s rights offering and issuance of the Successor’s debt.
|
2)
|
Changes in cash and cash equivalents included the following (in thousands):
|
Proceeds from equity investment from holders of Old Second Lien Notes
|
$
|
19,250
|
|
Proceeds from rights offering
|
255,750
|
|
|
Borrowings under the Successor's Term Loan
|
125,000
|
|
|
Removal of restriction on cash balance
|
102,556
|
|
|
Payment of holders of claims under the Predecessor Credit Facility
|
(500,266
|
)
|
|
Payment of interest and fees under the Predecessor Credit Facility
|
(3,390
|
)
|
|
Payment of Successor Credit Facility fees
|
(9,300
|
)
|
|
Payment of professional fees
|
(2,468
|
)
|
|
Funding of the general unsecured claims cash distribution pools
|
(6,750
|
)
|
|
Funding of the professional fees escrow account
|
(21,705
|
)
|
|
Changes in cash and cash equivalents
|
$
|
(41,323
|
)
|
3)
|
Reflects the write-off of lease incentive costs due to the rejection of the related lease contract.
|
4)
|
Net change to restricted cash includes the following:
|
Removal of restriction on cash balance
|
$
|
(102,556
|
)
|
Funding of the general unsecured claims cash distribution pools
|
6,750
|
|
|
Funding of the professional fees escrow account
|
21,705
|
|
|
|
$
|
(74,101
|
)
|
5)
|
Primarily reflects the write-off of the Predecessor’s equity offering costs.
|
6)
|
Reflects reinstatement of payables for the general unsecured claims and trade claims cash distribution pool.
|
7)
|
Reflects payment of accrued interest related to Predecessor Credit Facility and Predecessor debtor-in-possession credit facility of
$3.4 million
and the capitalization of approximately
$5.1 million
accrued interest on the Old Second Lien Notes into the principal amount of the Senior Notes due 2024.
|
8)
|
Net increase in other accrued expenses reflect (in thousands):
|
Recognition of payables for the professional fees escrow account
|
$
|
12,627
|
|
Write-off of accrued non-cash compensation related to Phantom Units granted
|
(330
|
)
|
|
Net increase in accounts payable and accrued expenses
|
$
|
12,297
|
|
9)
|
Reflects the repayment of outstanding borrowings under the Predecessor Credit Facility of approximately
$500.3 million
and the conversion of the remaining outstanding debt to Successor Credit Facility and the Senior Notes due 2024 to Long-Term Debt, net of the write-off of deferred financing fees.
|
10)
|
Reflects the write-off of deferred rent due to the rejection of the related lease contract.
|
11)
|
Reflects
$855.0 million
of outstanding borrowings under the Successor Credit Facility, which includes a
$730.0 million
revolving loan and a
$125.0 million
Term Loan. The adjustment also reflects the issuance of Senior Notes due 2024 of
$80.7 million
. The amounts are presented net of capitalized deferred financing fees related to each debt.
|
12)
|
Settlement of Liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):
|
Accounts payable and accrued expenses
|
$
|
36,224
|
|
Accrued interest payable
|
10,737
|
|
|
Debt
|
432,950
|
|
|
Total liabilities subject to compromise
|
479,911
|
|
|
Reinstatement of liability for the general unsecured claims
|
(4,978
|
)
|
|
Reinstatement of liability for settlement of an unsecured claim
|
(5,000
|
)
|
|
Issuance of common shares to holders of general unsecured claims
|
(1,089
|
)
|
|
Issuance of common shares to holders of Senior Notes claims
|
(16,715
|
)
|
|
Gain on settlement of liabilities subject to compromise
|
$
|
452,129
|
|
13)
|
Net change in Predecessor common units reflects (in thousands):
|
Recognition of gain on settlement of liabilities subject to compromise
|
$
|
452,129
|
|
Cancellation of Predecessor Preferred units
|
335,444
|
|
|
Cancellation of Predecessor Class B units
|
7,615
|
|
|
Write-off of deferred financing costs and debt discounts
|
(4,917
|
)
|
|
Recognition of professional and success fees
|
(14,968
|
)
|
|
Fair value of warrants issued to Predecessor unitholders
|
(11,734
|
)
|
|
Fair value of shares issued to Predecessor unitholders
|
(517
|
)
|
|
Terminated contracts
|
165
|
|
|
Net change in Predecessor Common units
|
$
|
763,217
|
|
14)
|
Net change in Successor equity reflects net increase in capital accounts as follows (in thousands):
|
Issuance of common stock to general unsecured creditors
|
$
|
1,089
|
|
Issuance of common stock to holders of Senior Notes claims
|
16,715
|
|
|
Issuance of common stock to Predecessor preferred unitholders
|
517
|
|
|
Issuance of common stock for the second lien equity investment
|
19,250
|
|
|
Issuance of common stock pursuant to the rights offering
|
255,750
|
|
|
Issuance of warrants
|
11,734
|
|
|
Net increase in capital accounts
|
305,055
|
|
|
Par value of common stock
|
(20
|
)
|
|
Change in additional paid-in capital
|
$
|
305,035
|
|
15)
|
Reflects a change in accounting policy from the entitlements method for natural gas production imbalances in accordance with the adoption of ASC 606.
|
16)
|
Reflects fair value adjustment for oil inventory.
|
17)
|
Reflects the adjustments to oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion. The following table summarizes the components of oil and natural gas properties as of the Convenience Date (in thousands):
|
|
Successor
|
|
|
Predecessor
|
||||
|
Fair Value
|
|
|
Historical Book Value
|
||||
Proved properties
|
$
|
1,511,083
|
|
|
|
$
|
4,635,867
|
|
Unproved properties
|
95,611
|
|
|
|
—
|
|
||
|
1,606,694
|
|
|
|
4,635,867
|
|
||
Less: accumulated depletion and amortization
|
—
|
|
|
|
(3,916,889
|
)
|
||
|
$
|
1,606,694
|
|
|
|
$
|
718,978
|
|
18)
|
Reflects the write-off of Predecessor goodwill.
|
19)
|
Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Convenience Date (in thousands):
|
|
Successor
|
|
|
Predecessor
|
||||
|
Fair Value
|
|
|
Historical Book Value
|
||||
Gas gathering assets
|
$
|
4,196
|
|
|
|
$
|
19,942
|
|
Office equipment and furniture
|
574
|
|
|
|
5,847
|
|
||
Buildings and leasehold improvements
|
57
|
|
|
|
836
|
|
||
Vehicles
|
1,311
|
|
|
|
1,549
|
|
||
|
6,138
|
|
|
|
28,174
|
|
||
Less: accumulated depreciation
|
—
|
|
|
|
(13,657
|
)
|
||
|
$
|
6,138
|
|
|
|
$
|
14,517
|
|
20)
|
Reflects an adjustment for the intangible asset related to the Company’s nickel gas contract of
$5.6 million
and the write-off of deferred tax asset of
$4.1 million
.
|
21)
|
Reflects the adjustment of current portion of financing obligation to fair value and write-off of deferred rent.
|
22)
|
Reflects the adjustment of long-term portion of financing obligation to fair value.
|
23)
|
Primarily reflects the fair value adjustment of asset retirement obligations (“ARO”) to fair value of approximately
$145.2 million
, of which
$136.8 million
is reflected as long-term ARO and
$8.4 million
of current ARO shown in other current liabilities. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Refer to Note 9, “Asset Retirement Obligations”
for further details of the Company's asset retirement obligations.
|
24)
|
Reflects the write-off of deferred tax liabilities.
|
25)
|
Reflects the cumulative impact of the fresh-start accounting adjustments discussed above and the elimination of Common units (Predecessor).
|
|
Successor
|
|
|
Predecessor
|
||||
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
||||
Gain on settlement of Liabilities subject to compromise
|
$
|
—
|
|
|
|
$
|
452,129
|
|
Fresh-start accounting adjustments
|
—
|
|
|
|
781,520
|
|
||
Issuance of common shares and warrants
|
—
|
|
|
|
(214,140
|
)
|
||
Legal and other professional fees
|
(6,488
|
)
|
|
|
(58,482
|
)
|
||
Recognition of additional unsecured claims
|
—
|
|
|
|
(31,346
|
)
|
||
Write-off of deferred financing costs and debt discounts
|
—
|
|
|
|
(21,361
|
)
|
||
Terminated contracts
|
—
|
|
|
|
165
|
|
||
Reorganization items
|
$
|
(6,488
|
)
|
|
|
$
|
908,485
|
|
|
Successor
|
||||||||||
|
Five Months Ended December 31, 2017
|
||||||||||
|
Under ASC 606
|
|
Under ASC 605
|
|
Increase
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
72,557
|
|
|
$
|
72,557
|
|
|
$
|
—
|
|
Natural gas sales
|
96,236
|
|
|
81,986
|
|
|
14,250
|
|
|||
NGLs sales
|
36,825
|
|
|
31,873
|
|
|
4,952
|
|
|||
Oil, natural gas and NGLs sales
|
205,618
|
|
|
186,416
|
|
|
19,202
|
|
|||
Net losses on commodity derivative contracts
|
(55,857
|
)
|
|
(55,857
|
)
|
|
—
|
|
|||
Total revenues and gains (losses) on derivatives
|
$
|
149,761
|
|
|
$
|
130,559
|
|
|
$
|
19,202
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Transportation, gathering, processing, and compression
|
$
|
19,202
|
|
|
$
|
—
|
|
|
$
|
19,202
|
|
Net loss
|
$
|
(111,278
|
)
|
|
$
|
(111,278
|
)
|
|
$
|
—
|
|
•
|
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 consolidated statements of operations.
|
Consideration
|
|
|
||
Market value of Vanguard’s common units issued to LRE unitholders
|
|
$
|
123,276
|
|
Long-term debt assumed
|
|
290,000
|
|
|
|
|
413,276
|
|
|
Add: fair value of liabilities assumed
|
|
|
||
Accounts payable and accrued liabilities
|
|
5,606
|
|
|
Other current liabilities
|
|
9,018
|
|
|
Asset retirement obligations
|
|
39,595
|
|
|
Amount attributable to liabilities assumed
|
|
54,219
|
|
|
Less: fair value of assets acquired
|
|
|
||
Cash
|
|
11,532
|
|
|
Trade accounts receivable
|
|
6,822
|
|
|
Other current assets
|
|
4,172
|
|
|
Oil and natural gas properties
|
|
209,463
|
|
|
Derivative assets
|
|
78,725
|
|
|
Other assets
|
|
267
|
|
|
Amount attributable assets acquired
|
|
310,981
|
|
|
Goodwill
|
|
$
|
156,514
|
|
Consideration
|
|
|
||
Market value of Vanguard’s common units issued to Eagle Rock unitholders
|
|
$
|
258,282
|
|
Long-term debt assumed
|
|
156,550
|
|
|
Replacement share-based payment awards attributable to pre-combination services
|
|
346
|
|
|
|
|
415,178
|
|
|
Add: fair value of liabilities assumed
|
|
|
||
Accounts payable and accrued liabilities
|
|
54,437
|
|
|
Other current liabilities
|
|
2,206
|
|
|
Derivative liabilities
|
|
2,201
|
|
|
Asset retirement obligations
|
|
48,633
|
|
|
Deferred tax liability
|
|
39,327
|
|
|
Other long-term liabilities
|
|
1,244
|
|
|
Amount attributable to liabilities assumed
|
|
148,048
|
|
|
Less: fair value of assets acquired
|
|
|
||
Cash
|
|
6,971
|
|
|
Trade accounts receivable
|
|
13,746
|
|
|
Other current assets
|
|
15,664
|
|
|
Oil and natural gas properties
|
|
462,715
|
|
|
Derivative assets
|
|
90,234
|
|
|
Other assets
|
|
9,734
|
|
|
Amount attributable assets acquired
|
|
599,064
|
|
|
Bargain Purchase Gain
|
|
$
|
(35,838
|
)
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||
Description
|
|
Interest Rate
|
|
Maturity Date
|
|
December 31, 2017
|
|
|
December 31, 2016
|
||||
Successor Credit Facility
|
|
Variable (1)
|
|
February 1, 2021
|
|
$
|
700,000
|
|
|
|
$
|
—
|
|
Successor term loan
|
|
Variable (2)
|
|
May 1, 2021
|
|
124,688
|
|
|
|
—
|
|
||
Senior Notes due 2024
|
|
9.0%
|
|
February 15, 2024
|
|
80,722
|
|
|
|
—
|
|
||
Predecessor Credit Facility
|
|
Variable (3)
|
|
April 16, 2018
|
|
—
|
|
|
|
1,269,000
|
|
||
Senior Notes due 2019
|
|
8.38% (4)
|
|
June 1, 2019
|
|
—
|
|
|
|
51,120
|
|
||
Senior Notes due 2020
|
|
7.875% (5)
|
|
April 1, 2020
|
|
—
|
|
|
|
381,830
|
|
||
Senior Notes due 2023
|
|
7.0%
|
|
February 15, 2023
|
|
—
|
|
|
|
75,634
|
|
||
Lease Financing Obligation
|
|
4.16%
|
|
August 10, 2020 (6)
|
|
15,205
|
|
|
|
20,167
|
|
||
Unamortized discount on Senior Notes
|
|
|
|
—
|
|
|
|
(13,167
|
)
|
||||
Unamortized deferred financing costs
|
|
|
|
(8,639
|
)
|
|
|
(11,072
|
)
|
||||
Total Debt
|
|
|
|
|
|
$
|
911,976
|
|
|
|
$
|
1,773,512
|
|
Less:
|
|
|
|
|
|
|
|
|
|
||||
Long-term debt classified as current
|
|
|
|
—
|
|
|
|
(1,753,345
|
)
|
||||
Current portion of Term Loan
|
|
|
|
(1,250
|
)
|
|
|
—
|
|
||||
Current portion of Lease Financing Obligation
|
|
|
|
(4,750
|
)
|
|
|
(4,692
|
)
|
||||
Total long-term debt
|
|
|
|
|
|
$
|
905,976
|
|
|
|
$
|
15,475
|
|
Year
|
|
Required Payments
|
||
2018
|
|
$
|
1,250
|
|
2019
|
|
1,250
|
|
|
2020
|
|
1,250
|
|
|
2021 through Maturity date
|
|
120,938
|
|
Year
|
|
Percentage
|
|
2020
|
|
106.75
|
%
|
2021
|
|
104.50
|
%
|
2022
|
|
102.25
|
%
|
2023 and thereafter
|
|
100.00
|
%
|
|
|
Gas
|
|
Oil
|
|
NGLs
|
|||||||||||||||
Contract Period
|
|
MMBtu
|
|
Weighted
Average
Fixed Price
|
|
Bbls
|
|
Weighted Average
WTI Price
|
|
Gallons
|
|
Weighted Average
Fixed Price |
|||||||||
January 1, 2018 - December 31, 2018
|
|
70,242,000
|
|
|
$
|
3.00
|
|
|
2,712,450
|
|
|
$
|
46.59
|
|
|
56,721,000
|
|
|
$
|
0.61
|
|
January 1, 2019 - December 31, 2019
|
|
52,539,000
|
|
|
$
|
2.79
|
|
|
1,858,200
|
|
|
$
|
48.50
|
|
|
—
|
|
|
$
|
—
|
|
January 1, 2020 - December 31, 2020
|
|
47,227,500
|
|
|
$
|
2.75
|
|
|
1,393,800
|
|
|
$
|
49.53
|
|
|
—
|
|
|
$
|
—
|
|
|
|
Gas
|
Oil
|
|||||||||||||||||||
Contract Period
|
|
MMBtu
|
|
Floor Price ($/MMBtu)
|
|
Ceiling Price ($/MMBtu)
|
|
Bbls
|
|
Floor Price ($/Bbl)
|
|
Ceiling Price ($/Bbl)
|
||||||||||
January 1, 2018 – December 31, 2018
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
January 1, 2019 - December 31, 2019
|
|
4,125,000
|
|
|
$
|
2.60
|
|
|
$
|
3.00
|
|
|
575,730
|
|
|
$
|
43.81
|
|
|
$
|
54.04
|
|
January 1, 2020 - December 31, 2020
|
|
5,490,000
|
|
|
$
|
2.60
|
|
|
$
|
3.00
|
|
|
659,340
|
|
|
$
|
44.17
|
|
|
$
|
55.00
|
|
|
|
Successor
|
||||||||||
|
|
December 31, 2017
|
||||||||||
Offsetting Derivative Assets:
|
|
Gross Amounts of Recognized Assets
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
Commodity price derivative contracts
|
|
$
|
15,264
|
|
|
$
|
(13,006
|
)
|
|
$
|
2,258
|
|
Total derivative instruments
|
|
$
|
15,264
|
|
|
$
|
(13,006
|
)
|
|
$
|
2,258
|
|
|
|
|
|
|
|
|
||||||
Offsetting Derivative Liabilities:
|
|
Gross Amounts of Recognized Liabilities
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
Commodity price derivative contracts
|
|
$
|
(79,701
|
)
|
|
$
|
13,006
|
|
|
$
|
(66,695
|
)
|
Total derivative instruments
|
|
$
|
(79,701
|
)
|
|
$
|
13,006
|
|
|
$
|
(66,695
|
)
|
|
|
Predecessor
|
||
|
|
December 31, 2016
|
||
Derivative Liabilities:
|
|
Amount Presented in the Consolidated Balance Sheets
|
||
Interest rate derivative contracts
|
|
$
|
(125
|
)
|
Total derivative instruments
|
|
$
|
(125
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
Derivative asset (liability) at beginning of period, net
|
$
|
(24,894
|
)
|
|
|
$
|
(125
|
)
|
|
$
|
316,691
|
|
|
$
|
220,734
|
|
Purchases
|
|
|
|
|
|
|
|
|
||||||||
Fair value of derivatives acquired
|
—
|
|
|
|
—
|
|
|
—
|
|
|
195,273
|
|
||||
Net premiums and fees (received) paid for derivative contracts
|
—
|
|
|
|
—
|
|
|
(2,444
|
)
|
|
7,126
|
|
||||
Net gains (losses) on commodity and interest rate derivative contracts
|
(55,857
|
)
|
|
|
(24,857
|
)
|
|
(46,939
|
)
|
|
169,569
|
|
||||
Settlements
|
|
|
|
|
|
|
|
|
||||||||
Cash settlements paid (received) on matured commodity derivative contracts
|
12,174
|
|
|
|
(7
|
)
|
|
(226,876
|
)
|
|
(211,723
|
)
|
||||
Cash settlements paid on matured interest rate derivative contracts
|
—
|
|
|
|
95
|
|
|
13,398
|
|
|
5,227
|
|
||||
Termination of derivative contracts
|
4,140
|
|
|
|
—
|
|
|
(53,955
|
)
|
|
(69,515
|
)
|
||||
Derivative asset (liability) at end of period, net
|
$
|
(64,437
|
)
|
|
|
$
|
(24,894
|
)
|
|
$
|
(125
|
)
|
|
$
|
316,691
|
|
Level 1
|
|
Quoted prices for identical instruments in active markets.
|
|
|
|
Level 2
|
|
Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
|
|
|
|
Level 3
|
|
Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.
|
|
|
Successor
|
||||||
|
|
December 31, 2017
|
||||||
|
|
Fair Value
Measurements
Using Level 2
|
|
Assets/Liabilities at Fair Value
|
||||
|
|
(in thousands)
|
||||||
Assets:
|
|
|
|
|
||||
Commodity price derivative contracts
|
|
$
|
2,258
|
|
|
$
|
2,258
|
|
Total derivative instruments
|
|
$
|
2,258
|
|
|
$
|
2,258
|
|
|
|
|
|
|
||||
Liabilities:
|
|
|
|
|
|
|
||
Commodity price derivative contracts
|
|
$
|
(66,695
|
)
|
|
$
|
(66,695
|
)
|
Total derivative instruments
|
|
$
|
(66,695
|
)
|
|
$
|
(66,695
|
)
|
|
|
Predecessor
|
||||||
|
|
December 31, 2016
|
||||||
|
|
Fair Value
Measurements Using Level 2 |
|
Assets/Liabilities at Fair Value
|
||||
|
|
(in thousands)
|
||||||
Liabilities:
|
|
|
|
|
|
|
||
Interest rate derivative contracts
|
|
$
|
(125
|
)
|
|
$
|
(125
|
)
|
Total derivative instruments
|
|
$
|
(125
|
)
|
|
$
|
(125
|
)
|
|
Predecessor
|
||
|
2016
|
||
|
(in thousands)
|
||
Unobservable inputs at January 1,
|
$
|
(5,933
|
)
|
Total gains
|
11,838
|
|
|
Settlements
|
(5,905
|
)
|
|
Unobservable inputs at December 31,
|
$
|
—
|
|
|
|
||
Change in fair value included in earnings related to derivatives still held as of December 31,
|
$
|
—
|
|
Asset retirement obligation at January 1, 2016
|
|
$
|
271,456
|
|
Liabilities added during the current period
|
|
713
|
|
|
Accretion expense
|
|
12,145
|
|
|
Change in estimate
|
|
1,267
|
|
|
Disposition of properties
|
|
(10,915
|
)
|
|
Retirements
|
|
(2,230
|
)
|
|
Asset retirement obligations as of December 31, 2016 (Predecessor)
|
|
272,436
|
|
|
Liabilities added during the current period
|
|
555
|
|
|
Accretion expense
|
|
6,795
|
|
|
Retirements
|
|
(1,161
|
)
|
|
Liabilities related to assets divested
|
|
(10,107
|
)
|
|
Change in estimate
|
|
(29
|
)
|
|
Asset retirement obligation at July 31, 2017 (Predecessor)
|
|
268,489
|
|
|
Fresh-start adjustment
(1)
|
|
(123,320
|
)
|
|
Asset retirement obligation at July 31, 2017 (Successor)
|
|
145,169
|
|
|
Liabilities added during the current period
|
|
10,540
|
|
|
Accretion expense
|
|
3,975
|
|
|
Liabilities related to assets divested
|
|
(5,066
|
)
|
|
Retirements
|
|
(812
|
)
|
|
Change in estimate
|
|
3,618
|
|
|
Asset retirement obligation at December 31, 2017 (Successor)
|
|
157,424
|
|
|
Less: current obligations
|
|
(5,707
|
)
|
|
Long-term asset retirement obligation at December 31, 2017 (Successor)
|
|
$
|
151,717
|
|
|
|
Demand Charges
|
||
|
|
(in thousands)
|
||
2018
|
|
$
|
1,009
|
|
2019
|
|
820
|
|
|
2020
|
|
410
|
|
|
Total
|
|
$
|
2,239
|
|
|
|
Lease Payments
|
||
|
|
(in thousands)
|
||
2018
|
|
$
|
1,202
|
|
2019
|
|
1,149
|
|
|
2020
|
|
1,135
|
|
|
2021
|
|
1,169
|
|
|
2022
|
|
1,204
|
|
|
Thereafter
|
|
4,504
|
|
|
Total
|
|
$
|
10,363
|
|
•
|
678,464
shares of Common Stock were issued pro rata to holders of claims arising under the Senior Notes;
|
•
|
1,283,333
shares of Common Stock were issued pro rata to holders of the Existing Notes in exchange for a fully committed
$19.25
million investment;
|
•
|
678,405
shares of Common Stock were issued to participants in the rights offering extended by the Debtors to certain holders of claims arising under the Senior Notes (including certain of the commitment parties party to the Backstop Commitment Agreement);
|
•
|
7,846,595
shares of Common Stock were issued to participants who were eligible to participate in the accredited investor rights offering extended by the Debtors to certain holders of claims arising under the Senior Notes (including certain of the commitment parties party to the Backstop Commitment Agreement);
|
•
|
1,023,000
shares of Common Stock were issued to commitment parties under the Amended and Restated Backstop Commitment Agreement in respect of the premium due thereunder;
|
•
|
8,525,000
shares of Common Stock were issued to commitment parties under the Amended and Restated Backstop Commitment Agreement in connection with their backstop obligation thereunder together with
1,482,021
shares of New Common Stock reflecting shares purchased by such commitment parties in respect of unsubscribed shares in the rights offerings; and
|
•
|
20,983
shares of Common Stock were issued to holders of the Predecessor’s Preferred Units; and
|
•
|
44,220
shares of Common Stock were reserved for general unsecured claimholders. These shares were ultimately issued on December 21, 2017.
|
|
|
Number of
Non-vested Restricted Units
|
|
Weighted Average
Grant Date
Fair Value
|
|||
Non-vested restricted units at December 31, 2016
|
|
647,784
|
|
|
$
|
19.14
|
|
Forfeited
|
|
(14,637
|
)
|
|
$
|
16.93
|
|
Vested
|
|
(257,497
|
)
|
|
$
|
20.80
|
|
Non-vested restricted units at July 31, 2017
|
|
375,650
|
|
|
$
|
18.11
|
|
Restricted units canceled upon emergence from bankruptcy
|
|
(375,650
|
)
|
|
$
|
18.11
|
|
Restricted units upon emergence
|
|
—
|
|
|
$
|
—
|
|
|
|
Number of
Non-vested
Phantom Units
|
|
Weighted Average
Grant Date
Fair Value
|
|||
Non-vested phantom units at December 31, 2016
|
|
3,628,529
|
|
|
$
|
2.96
|
|
Granted
|
|
11,092,708
|
|
|
$
|
0.67
|
|
Forfeited
|
|
(73,257
|
)
|
|
$
|
2.04
|
|
Vested
|
|
(956,830
|
)
|
|
$
|
4.31
|
|
Non-vested phantom units at July 31, 2017
|
|
13,691,150
|
|
|
$
|
1.02
|
|
Phantom units canceled upon emergence from bankruptcy
|
|
(13,691,150
|
)
|
|
$
|
1.02
|
|
Phantom units upon emergence
|
|
—
|
|
|
$
|
—
|
|
|
Successor
|
|
|
Five Months Ended
December 31, 2017
|
|
Federal statutory rate
|
35.0
|
%
|
Permanent items
|
(2.0
|
)%
|
Federal statutory rate change
|
(17.8
|
)%
|
State, net of federal tax benefit
|
3.0
|
%
|
Valuation allowance adjustments
|
(18.2
|
)%
|
Effective rate
|
—
|
%
|
|
Successor
|
||
|
December 31, 2017
|
||
Deferred tax assets:
|
|
||
Net operating loss carryforwards
|
$
|
2,957
|
|
Asset retirement obligation
|
39,084
|
|
|
Derivative instruments
|
7,655
|
|
|
Accrued Liabilities
|
6,681
|
|
|
Bad debts
|
1,489
|
|
|
Investment in subsidiaries
|
4,827
|
|
|
Other
|
31
|
|
|
Valuation allowance
|
(35,447
|
)
|
|
Total deferred tax assets
|
27,277
|
|
|
Deferred tax liabilities:
|
|
||
Oil & natural gas property
|
(27,277
|
)
|
|
Total deferred tax liabilities
|
(27,277
|
)
|
|
Net deferred tax assets (liabilities)
|
$
|
—
|
|
|
|
Predecessor
|
|
|
Successor
|
||||||||||||||||||||||||
(in thousands except per share/unit amounts)
|
|
Quarter Ended
|
|
Quarter Ended
|
|
One Month
Ended |
|
|
|
|
Two
Months Ended
|
|
Quarter Ended
|
|
|
||||||||||||||
|
|
March 31
|
|
June 30
|
|
July 31
|
|
Total
|
|
|
September 30
|
|
December 31
|
|
Total
|
||||||||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Oil, natural gas and NGLs sales
|
|
$
|
118,756
|
|
|
$
|
106,868
|
|
|
$
|
21,024
|
|
|
$
|
246,648
|
|
|
|
$
|
79,800
|
|
|
$
|
125,818
|
|
|
$
|
205,618
|
|
Net gains (losses) on commodity derivative contracts
|
|
7
|
|
|
(12,875
|
)
|
|
(12,019
|
)
|
|
(24,887
|
)
|
|
|
(32,352
|
)
|
|
(23,505
|
)
|
|
(55,857
|
)
|
|||||||
Total revenues
|
|
$
|
118,763
|
|
|
$
|
93,993
|
|
|
$
|
9,005
|
|
|
$
|
221,761
|
|
|
|
$
|
47,448
|
|
|
$
|
102,313
|
|
|
$
|
149,761
|
|
Total costs and expenses
(1)
|
|
$
|
84,570
|
|
|
$
|
81,066
|
|
|
$
|
29,836
|
|
|
$
|
195,472
|
|
|
|
$
|
75,105
|
|
|
$
|
112,562
|
|
|
$
|
187,667
|
|
Impairment of oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
47,640
|
|
|
$
|
47,640
|
|
Interest expense
|
|
$
|
16,440
|
|
|
$
|
13,832
|
|
|
$
|
5,004
|
|
|
$
|
35,276
|
|
|
|
$
|
9,615
|
|
|
$
|
14,589
|
|
|
$
|
24,204
|
|
Net gain on divestiture of oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
4,450
|
|
|
$
|
4,450
|
|
Reorganization items
|
|
$
|
(26,746
|
)
|
|
$
|
(53,221
|
)
|
|
$
|
988,452
|
|
|
$
|
908,485
|
|
|
|
$
|
—
|
|
|
$
|
(6,488
|
)
|
|
$
|
(6,488
|
)
|
Net income (loss)
|
|
$
|
(8,908
|
)
|
|
$
|
(53,871
|
)
|
|
$
|
963,090
|
|
|
$
|
900,311
|
|
|
|
$
|
(37,236
|
)
|
|
$
|
(74,042
|
)
|
|
$
|
(111,278
|
)
|
Net (income) loss attributable to non-controlling interest
|
|
$
|
(17
|
)
|
|
$
|
5
|
|
|
$
|
(1
|
)
|
|
$
|
(13
|
)
|
|
|
$
|
(61
|
)
|
|
$
|
(71
|
)
|
|
$
|
(132
|
)
|
Net income (loss) attributable to Vanguard shareholders/unitholders
|
|
$
|
(8,925
|
)
|
|
$
|
(53,866
|
)
|
|
$
|
963,089
|
|
|
$
|
900,298
|
|
|
|
$
|
(37,297
|
)
|
|
$
|
(74,113
|
)
|
|
$
|
(111,410
|
)
|
Distributions to Preferred unitholders
|
|
$
|
(2,230
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,230
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net income (loss) attributable to Common shareholders/Common and Class B unitholders
|
|
$
|
(11,155
|
)
|
|
$
|
(53,866
|
)
|
|
$
|
963,089
|
|
|
$
|
898,068
|
|
|
|
$
|
(37,297
|
)
|
|
$
|
(74,113
|
)
|
|
$
|
(111,410
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income (loss) per share/unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Basic and diluted
|
|
$
|
(0.08
|
)
|
|
$
|
(0.41
|
)
|
|
$
|
7.33
|
|
|
$
|
6.84
|
|
|
|
$
|
(1.86
|
)
|
|
$
|
(3.69
|
)
|
|
$
|
(5.55
|
)
|
|
|
Quarters Ended
|
||||||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total
|
||||||||||
|
|
(in thousands, except per unit amounts)
|
||||||||||||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil, natural gas and NGLs sales
|
|
$
|
81,440
|
|
|
$
|
93,476
|
|
|
$
|
105,186
|
|
|
$
|
108,578
|
|
|
$
|
388,680
|
|
Net gains (losses) on commodity derivative contracts
|
|
31,759
|
|
|
(68,610
|
)
|
|
21,099
|
|
|
(28,320
|
)
|
|
(44,072
|
)
|
|||||
Total revenues
|
|
$
|
113,199
|
|
|
$
|
24,866
|
|
|
$
|
126,285
|
|
|
$
|
80,258
|
|
|
$
|
344,608
|
|
Total costs and expenses
(1)
|
|
$
|
110,070
|
|
|
$
|
100,185
|
|
|
$
|
94,759
|
|
|
$
|
94,603
|
|
|
$
|
399,617
|
|
Impairment of oil and natural gas properties
|
|
$
|
207,764
|
|
|
$
|
157,894
|
|
|
$
|
—
|
|
|
$
|
128,612
|
|
|
$
|
494,270
|
|
Impairment of goodwill
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
252,676
|
|
|
$
|
—
|
|
|
$
|
252,676
|
|
Interest expense
|
|
$
|
25,704
|
|
|
$
|
23,932
|
|
|
$
|
22,976
|
|
|
$
|
22,755
|
|
|
$
|
95,367
|
|
Net losses on acquisitions of oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
(1,665
|
)
|
|
$
|
(2,117
|
)
|
|
$
|
(1,197
|
)
|
|
$
|
(4,979
|
)
|
Gain on extinguishment of debt
|
|
$
|
89,714
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
89,714
|
|
Net loss
|
|
$
|
(145,260
|
)
|
|
$
|
(260,749
|
)
|
|
$
|
(245,368
|
)
|
|
$
|
(163,630
|
)
|
|
$
|
(815,007
|
)
|
Net (income) loss attributable to non-controlling interest
|
|
$
|
(24
|
)
|
|
$
|
(40
|
)
|
|
$
|
(27
|
)
|
|
$
|
9
|
|
|
$
|
(82
|
)
|
Net loss attributable to Vanguard unitholders
|
|
$
|
(145,284
|
)
|
|
$
|
(260,789
|
)
|
|
$
|
(245,395
|
)
|
|
$
|
(163,621
|
)
|
|
$
|
(815,089
|
)
|
Distributions to Preferred unitholders
|
|
$
|
(6,690
|
)
|
|
$
|
(6,689
|
)
|
|
$
|
(6,690
|
)
|
|
$
|
(6,689
|
)
|
|
$
|
(26,758
|
)
|
Net loss attributable to Common and Class B unitholders
|
|
$
|
(151,974
|
)
|
|
$
|
(267,478
|
)
|
|
$
|
(252,085
|
)
|
|
$
|
(170,310
|
)
|
|
$
|
(841,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net loss per Common and Class B unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Basic and diluted
|
|
$
|
(1.16
|
)
|
|
$
|
(2.04
|
)
|
|
$
|
(1.92
|
)
|
|
$
|
(1.30
|
)
|
|
$
|
(6.41
|
)
|
(1)
|
Includes lease operating expenses, production and other taxes, depreciation, depletion, amortization and accretion, and selling, general and administration expenses.
|
|
|
Successful Efforts Method
|
|
Full Cost Method
|
|
||||
|
|
Successor
|
|
Predecessor
|
|
||||
|
|
2017
|
|
2016
|
|
||||
|
|
(in thousands)
|
|
||||||
Proved properties
|
|
$
|
1,560,552
|
|
|
$
|
4,725,692
|
|
|
Unproved properties
|
|
85,393
|
|
|
—
|
|
|
||
|
|
1,645,945
|
|
|
4,725,692
|
|
|
||
Aggregate accumulated depletion, amortization and impairment
|
|
(112,553
|
)
|
|
(3,867,439
|
)
|
|
||
Net capitalized costs
|
|
$
|
1,533,392
|
|
|
$
|
858,253
|
|
|
|
|
Successful Efforts Method
|
|
|
Full Cost Method
|
||||||||||||
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
|
Years Ended December 31,
|
||||||||||
|
|
|
|
|
2016
|
|
2015
|
||||||||||
|
|
(in thousands)
|
|
|
|
|
|
|
|
||||||||
Property acquisition costs
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
707,853
|
|
Development costs
|
|
79,246
|
|
|
|
46,315
|
|
|
64,537
|
|
|
112,639
|
|
||||
Total cost incurred
|
|
$
|
79,246
|
|
|
|
$
|
46,315
|
|
|
$
|
64,537
|
|
|
$
|
820,492
|
|
|
|
Gas (in MMcf)
|
|
Oil (in MBbls)
|
|
NGL (in MBbls)
|
|||
Net proved reserves
|
|
|
|
|
|
|
|
|
|
January 1, 2015
|
|
1,475,867
|
|
|
50,049
|
|
|
42,529
|
|
Revisions of previous estimates
|
|
(133,234)
|
|
|
(4,208)
|
|
|
(2,151)
|
|
Extensions, discoveries and other
|
|
46,664
|
|
|
640
|
|
|
659
|
|
Purchases of reserves in place
|
|
271,504
|
|
|
21,826
|
|
|
20,836
|
|
Sales of reserves in place
|
|
—
|
|
|
(225)
|
|
|
—
|
|
Production
|
|
(106,615)
|
|
|
(4,008)
|
|
|
(3,489)
|
|
December 31, 2015
|
|
1,554,186
|
|
|
64,074
|
|
|
58,384
|
|
Revisions of previous estimates
|
|
(438,527)
|
|
|
(11,052)
|
|
|
(5,823)
|
|
Extensions, discoveries and other
|
|
14,617
|
|
|
722
|
|
|
126
|
|
Purchases of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
|
(133,253
|
)
|
|
(6,792)
|
|
|
(12,217
|
)
|
Production
|
|
(108,107)
|
|
|
(4,660)
|
|
|
(3,716)
|
|
December 31, 2016
|
|
888,916
|
|
|
42,292
|
|
|
36,754
|
|
Revisions of previous estimates
|
|
(35,865)
|
|
|
(1,716)
|
|
|
(2,782)
|
|
Extensions, discoveries and other
|
|
604,009
|
|
|
6,391
|
|
|
8,126
|
|
Purchases of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
|
(5,462)
|
|
|
(4,229)
|
|
|
(424
|
)
|
Production
|
|
(94,009)
|
|
|
(3,768)
|
|
|
(3,319)
|
|
December 31, 2017
|
|
1,357,589
|
|
|
38,970
|
|
|
38,355
|
|
|
|
|
|
|
|
|
|||
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
1,069,942
|
|
|
54,945
|
|
|
42,140
|
|
December 31, 2016
|
|
888,916
|
|
|
42,292
|
|
|
36,754
|
|
December 31, 2017
|
|
831,479
|
|
|
34,257
|
|
|
31,381
|
|
|
|
|
|
|
|
|
|||
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
484,244
|
|
|
9,129
|
|
|
16,244
|
|
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
|
526,110
|
|
|
4,713
|
|
|
6,974
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||||||||
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
Years Ended December 31,
|
|
||||||||||
|
|
|
|
2016
|
|
2015
|
|
||||||||||
|
|
(in thousands)
|
|
|
(in thousands)
|
|
|||||||||||
Production revenues
|
|
$
|
205,618
|
|
|
|
$
|
246,648
|
|
$
|
388,680
|
|
|
$
|
397,227
|
|
|
Production costs
(1)
|
|
(93,323
|
)
|
|
|
(108,278
|
)
|
(198,309
|
)
|
|
(187,230
|
)
|
|
||||
Depreciation, depletion and amortization
|
|
(70,826
|
)
|
|
|
(56,919
|
)
|
(134,338
|
)
|
|
(234,944
|
)
|
|
||||
Impairment of oil and natural gas properties
|
|
(47,640
|
)
|
|
|
—
|
|
(494,270
|
)
|
|
(1,842,317
|
)
|
|
||||
Results of operations from producing activities
|
|
$
|
(6,171
|
)
|
|
|
$
|
81,451
|
|
$
|
(438,237
|
)
|
|
$
|
(1,867,264
|
)
|
|
(1)
|
Production cost includes lease operating expenses, transportation, gathering, processing and compression
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Future cash inflows
|
|
$
|
5,514,270
|
|
|
$
|
3,661,078
|
|
|
$
|
7,500,445
|
|
Future production costs
|
|
(2,634,887
|
)
|
|
(2,244,373
|
)
|
|
(3,411,879
|
)
|
|||
Future development costs
|
|
(554,807
|
)
|
|
(55,298
|
)
|
|
(664,254
|
)
|
|||
Future net cash flows before income taxes
|
|
2,324,576
|
|
|
1,361,407
|
|
|
3,424,312
|
|
|||
Future income taxes
(1)
|
|
(232,912
|
)
|
|
—
|
|
|
—
|
|
|||
Future net cash flows
|
|
2,091,664
|
|
|
1,361,407
|
|
|
3,424,312
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
(1,018,036
|
)
|
|
(507,638
|
)
|
|
(1,716,133
|
)
|
|||
Standardized measure of discounted future net cash flows
(2)
|
|
$
|
1,073,628
|
|
|
$
|
853,769
|
|
|
$
|
1,708,179
|
|
(1)
|
Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations.There are no future income tax expenses at December 31, 2016, or December 31, 2015, because the Predecessor was not subject to federal income taxes. See Note 13 of the Notes to the Consolidated Financial Statements for additional information about income taxes.
|
(2)
|
Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”) and calculated net of the estimated future costs incurred in developing, producing and abandoning the proved reserves. Certain prior year estimates of future cash flows have been revised to conform to the current year calculation of estimated future net cash flows and costs related to proved oil and natural gas reserves.
|
|
|
Year Ended December 31,
(1)
|
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
||||||
|
|
(in thousands)
|
|
||||||||||
Sales and transfers, net of production costs
|
|
$
|
(250,667
|
)
|
|
$
|
(189,111
|
)
|
|
$
|
(209,997
|
)
|
|
Net changes in prices and production costs
|
|
360,867
|
|
|
(681,575
|
)
|
|
(1,790,820
|
)
|
|
|||
Extensions discoveries and improved recovery, less related costs
|
|
235,949
|
|
|
16,960
|
|
|
17,031
|
|
|
|||
Changes in estimated future development costs
|
|
30,584
|
|
|
312,032
|
|
|
278,884
|
|
|
|||
Previously estimated development costs incurred during the period
|
|
—
|
|
|
20,115
|
|
|
63,624
|
|
|
|||
Revision of previous quantity estimates
|
|
(55,606
|
)
|
|
(276,257
|
)
|
|
(134,818
|
)
|
|
|||
Accretion of discount
|
|
85,377
|
|
|
170,818
|
|
|
296,342
|
|
|
|||
Net change in income taxes
|
|
(121,155
|
)
|
|
—
|
|
|
—
|
|
|
|||
Purchases of reserves in place
|
|
—
|
|
|
—
|
|
|
520,367
|
|
|
|||
Sales of reserves in place
|
|
(32,989
|
)
|
|
(214,419
|
)
|
|
(4,468
|
)
|
|
|||
Change in production rates, timing and other
|
|
(32,501
|
)
|
|
(12,973
|
)
|
|
(291,389
|
)
|
|
|||
Net change
|
|
$
|
219,859
|
|
|
$
|
(854,410
|
)
|
|
$
|
(1,255,244
|
)
|
|
(1)
|
This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.
|
(a)
|
Evaluation of Disclosure Controls and Procedures
|
(b)
|
Management’s Annual Report on Internal Control Over Financial Reporting
|
•
|
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
•
|
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
•
|
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
(c)
|
Changes in Internal Control over Financial Reporting
|
Name
|
Age
|
Position with Vanguard
|
Director Since
|
R. Scott Sloan
|
53
|
President, Chief Executive Officer and Director
|
August 1, 2017
|
Joseph Citarrella
|
31
|
Independent Director and Chairman
|
August 1, 2017
|
Randall M. Albert
|
60
|
Independent Director
|
September 26, 2017
|
Michael Alexander
|
40
|
Independent Director
|
August 1, 2017
|
W. Greg Dunlevy
|
62
|
Independent Director
|
October 17, 2017
|
Joseph Hurliman Jr.
|
60
|
Independent Director
|
February 21, 2018
|
Graham Morris
|
45
|
Independent Director
|
August 1, 2017
|
Name
|
Age
|
Position with Vanguard
|
R. Scott Sloan
|
53
|
President, Chief Executive Officer and Director
|
Ryan Midgett
|
33
|
Chief Financial Officer
|
Britt Pence
|
57
|
Executive Vice President of Operations
|
Jonathan C. Curth
|
35
|
General Counsel, Corporate Secretary and Vice President of Land
|
•
|
R. Scott Sloan, our former Executive Vice President and Chief Financial Officer and current President and Chief Executive Officer;
|
•
|
Britt Pence, our Executive Vice President of Operations;
|
•
|
Scott W. Smith, our former President and Chief Executive Officer; and
|
•
|
Richard A. Robert, our former Executive Vice President and Chief Financial Officer.
|
Name and Principal Position
|
Year
|
Salary
(1)
|
Bonus
(2)
|
Stock
Awards (3) |
Non-Equity Incentive Plan Compensation
(4)
|
All Other Compensation
(5)
|
Total
|
|||||||||||||||
R. Scott Sloan, Current President & CEO and Former EVP & CFO
|
2017
|
$
|
133,384
|
|
$
|
127,500
|
|
|
$
|
24,375
|
|
|
$
|
—
|
|
|
$
|
8,003
|
|
$
|
293,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Britt Pence,
|
2017
|
$
|
450,000
|
|
$
|
595,000
|
|
|
$
|
1,575,000
|
|
|
$
|
—
|
|
|
$
|
230,979
|
|
$
|
2,850,979
|
|
EVP of Operations
|
2016
|
$
|
440,000
|
|
$
|
—
|
|
|
$
|
1,539,998
|
|
|
$
|
632,500
|
|
|
$
|
15,900
|
|
$
|
2,628,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Scott W. Smith,
|
2017
|
$
|
650,000
|
|
$
|
717,969
|
|
|
$
|
3,575,000
|
|
|
$
|
—
|
|
|
$
|
553,565
|
|
$
|
5,496,534
|
|
Former President & CEO
|
2016
|
$
|
600,000
|
|
$
|
—
|
|
|
$
|
3,300,001
|
|
|
$
|
862,500
|
|
|
$
|
15,900
|
|
$
|
4,778,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Richard A. Robert,
|
2017
|
$
|
408,333
|
|
$
|
464,272
|
|
|
$
|
1,960,000
|
|
|
$
|
—
|
|
|
$
|
1,566,885
|
|
$
|
4,399,490
|
|
Former EVP & CFO
|
2016
|
$
|
470,000
|
|
$
|
—
|
|
|
$
|
1,879,999
|
|
|
$
|
675,625
|
|
|
$
|
15,900
|
|
$
|
3,041,524
|
|
(1)
|
Fiscal year 2017 salaries presented for Messrs. Robert and Sloan are prorated for their service as principal financial officer from January 1, 2017 to September 26, 2017, and from September 26, 2017 to December 31, 2017, respectively. Mr. Sloan also received $19,361 in fees earned or paid in cash for his service as a non-employee director from August 1, 2017 until September 26, 2017.
|
(2)
|
With respect to Messrs. Smith, Robert and Pence, the 2017 bonus represents amounts accrued under the Predecessor’s Employment Agreements (as defined below), which were in effect prior to the Effective Date. Such payment includes a quarterly bonus accrued with respect to the fiscal quarters ended December 31, 2016, March 31, 2017 and June 30, 2017 but was not payable until after the Effective Date.
|
(3)
|
The amounts in this column reflect the aggregate grant date fair value, computed as of the grant date in accordance with FASB ASC Topic 718-Compensation - Stock Compensation. The equity awards granted to Messrs. Smith, Robert and Pence in 2017 were phantom unit awards granted on January 1, 2017 with respect to the 2016 performance year. In connection with the implementation of the Plan, all awards of the Predecessor’s equity were canceled as of the Effective Date. On October 31, 2017, Mr. Sloan received a stock award of 1,250 fully-vested RSUs, valued at $19.50 per share, in connection with his service as a non-employee director from August 1, 2017 until September 26, 2017.
|
(4)
|
Represents amounts paid for 2016 pursuant to our Predecessor’s annual cash incentive program with respect to the Adjusted EBITDA Results, Production Results, Lease Operating Expenses and Cash General & Administrative components.
|
(5)
|
Amount shown for Mr. Sloan in 2017 and other named executive officers in 2016 is the amount received in the form of matching contributions to our 401(k) Plan. With respect to Mr. Smith the 2017 other compensation amount is attributable to $537,365 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions. With respect to Mr. Pence the 2017 other compensation amount is attributable to $214,779 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions. With respect to Mr. Robert the 2017 other compensation amount is attributable to $1,225,000 in severance pay, $18,846 in accrued vacation, $306,839 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions.
|
|
Stock Awards
|
||||||
Name
|
Number of Unvested Shares or Units of Stock
|
Market Value of Unvested Shares or Units of Stock ($)
|
|||||
Scott W. Smith
(1)
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||
R. Scott Sloan
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||
Richard A. Robert
(1)
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||
Britt Pence
(1)
|
—
|
|
|
$
|
—
|
|
|
Name
(1)
|
Fees Earned or Paid in Cash ($)
|
|
Stock Awards ($)
|
Total ($)
|
||||||
Predecessor Board of Directors Pre-Emergence
|
|
|
|
|
|
|
|
|
|
|
W. Richard Anderson
(2)
|
$
|
93,750
|
|
|
$
|
157,718
|
|
$
|
251,468
|
|
Bruce W. McCullough
(2)
|
$
|
93,750
|
|
|
$
|
157,718
|
|
$
|
251,468
|
|
Loren Singletary
(2)
|
$
|
93,750
|
|
|
$
|
157,718
|
|
$
|
251,468
|
|
|
|
|
|
|
|
|
|
|
|
|
Board Post-Emergence
|
|
|
|
|
|
|
|
|
|
|
Joseph Citarrella
(3)
|
$
|
50,000
|
|
|
$
|
—
|
|
$
|
50,000
|
|
Randall Albert
(4)
|
$
|
25,000
|
|
|
$
|
97,500
|
|
$
|
122,500
|
|
Michael Alexander
(5)
|
$
|
50,000
|
|
|
$
|
—
|
|
$
|
50,000
|
|
W. Greg Dunlevy
(6)
|
$
|
31,250
|
|
|
$
|
97,500
|
|
$
|
128,750
|
|
Graham Morris
(7)
|
$
|
50,000
|
|
|
$
|
—
|
|
$
|
50,000
|
|
(1)
|
Messrs. Smith and Robert are not included in this table as they were also executive officers of the Predecessor and Successor and received no additional compensation for their service as directors. All compensation provided to or earned by Messrs. Smith and Robert for 2017 is reported in the Summary Compensation Table above. Certain compensation that Mr. Sloan received in respect of his service as a director is included in the Summary Compensation Table above.
|
(2)
|
Messrs. Anderson, McCullough and Singletary received prorated compensation of $125,000 in fees for their service as directors from January 1, 2017 to July 31, 2017. Messrs. Anderson, McCullough and Singletary each held 41,946 unvested phantom units, which became 100% vested on January 4, 2017. Upon vesting, Messrs. Anderson, McCullough and Singletary each received a cash payment totaling $32,717.88, the fair market value of the phantom units, based on the January 3, 2017 closing price of $0.78 per unit. Additionally, Messrs. Anderson, McCullough and Singletary each were granted phantom unit awards on January 4, 2017. Any equity issued by the Predecessor as compensation to the Predecessor’s Board of Directors was canceled effective as of August 1, 2017.
|
(3)
|
Mr. Citarrella is not personally compensated for his services on the Board; rather, his compensation is passed to Monarch, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Citarrella’s service as a director and as Chairman of the N&G Committee.
|
(4)
|
Mr. Albert received $25,000 for his service as non-management director from September 26, 2017 through December 31, 2017. He also received 5,000 RSUs, valued at $19.50 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. 25% of the
|
(5)
|
Mr. Alexander is not personally compensated for his services on the Board; rather, his compensation is passed to Marathon, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Alexander’s service as a director and as Chairman of the Strategic Opportunities Committee.
|
(6)
|
Mr. Dunlevy received $31,250 for his service as non-management director and as the Chairman of the Audit Committee from October 16, 2017 through December 31, 2017. He also received 5,000 RSUs, valued at $19.50 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. 25% of the RSUs vested on the Grant Date, October 31, 2017. The remaining RSUs shall vest ratably on the first three anniversaries of the Grant Date. Settlement of RSUs will be at the earliest of: (i) Mr. Dunlevy’s termination of service or (ii) a change in control event.
|
(7)
|
Mr. Morris is not personally compensated for his services on the Board; rather, his compensation is passed to Contrarian, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Morris’s service as a director and as Chairman of the Compensation Committee.
|
Plan Category
|
(a)
Number of securities to
be issued upon exercise
of outstanding options, warrants and rights
|
(b)
Weighted-average
exercise price of
outstanding options, warrants and rights
|
(c)
Number of securities remaining
available for future issuance
under equity compensation plans
(excluding securities
reflected in column (a))
|
|||||||||
Previously Approved by Stockholders: Stock Plan
|
|
—
|
|
|
$
|
—
|
|
|
|
—
|
|
|
Not Previously Approved by Stockholders:
|
|
11,250
|
|
(1)
|
$
|
—
|
|
|
|
2,222,083
|
|
(2)
|
(1)
|
This amount includes 11,250 deferred restricted stock units under the MIP. The subject shares are not included in the calculation in column (b) as the weighted-average exercise price of outstanding options, warrants, and rights in column (b) does not take restricted shares, restricted stock units, or other non-option awards into account.
|
(2)
|
The share reserve authorized for issuance under the MIP was approved by the Bankruptcy Court in connection with the Plan.
|
Name of Beneficial Owner
|
Shares
|
Percent of Class
|
|||
|
|
|
|
||
5% Owners
|
|
|
|
||
Marathon Asset Management, L.P.
(1)
|
4,958,230
|
|
24.7
|
|
%
|
Contrarian Capital Management, L.L.C.
(2)
|
3,266,141
|
|
16.2
|
|
%
|
Morgan Stanley & Co. LLC
(3)
|
2,210,042
|
|
11.0
|
|
%
|
Monarch Alternative Capital LP
(4)
|
2,045,773
|
|
10.2
|
|
%
|
J.P. Morgan Securities LLC
(5)
|
1,468,528
|
|
7.3
|
|
%
|
FMR LLC
(6)
|
1,209,218
|
|
6.0
|
|
%
|
|
|
|
|
||
Directors
|
|
|
|
||
Randall M. Albert
|
1,250
(7)
|
|
*
|
|
|
Michael Alexander
|
—
|
|
—
|
|
|
Joseph Citarrella
|
—
|
|
—
|
|
|
W. Greg Dunlevy
|
1,250
(8)
|
|
*
|
|
|
Graham Morris
|
—
|
|
—
|
|
|
Joseph Hurliman Jr.
|
—
|
|
—
|
|
|
|
|
|
|
||
Named Executive Officers
|
|
|
|
||
R. Scott Sloan
|
1,250
(9)
|
|
*
|
|
|
Britt Pence
|
—
|
|
—
|
|
|
Richard A. Robert
|
—
|
|
—
|
|
|
Scott W. Smith
|
—
|
|
—
|
|
|
|
|
|
|
||
All directors and executive officers as a group (13 persons)
|
3,750
|
|
*
|
|
%
|
(1)
|
Bruce Richards and Louis Hanover, are managing members of Marathon Asset Management GP LLC, general partner of Marathon, which acts as investment advisor to certain funds and accounts. Michael V. Alexander, an employee of Marathon and/or one of its affiliates, is a member of the Board. Mr. Alexander does not individually hold or otherwise beneficially own any securities of Vanguard Natural Resources, Inc. Mr. Alexander disclaims beneficial ownership of any such securities, except to the extent of his pecuniary interest therein. The number of shares beneficially owned includes 2,646 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Bluegrass Credit Fund LP, 8,220 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Centre Street Partnership, 2,850 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Credit Dislocation Fund LP, 14,154 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Special Opportunity Master Fund LTD, 2,080 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Master SIF SICAV-SIF, and 3,237 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by TRS Credit Fund LP that, in each case, are exercisable within 60 days of
March 7, 2018
. The business address of these funds and accounts is One Bryant Park, 38th Floor, New York, NY 10036.
|
(2)
|
Contrarian is the general partner of Contrarian Advantage-B, LP (“TCAB”). The managing member of Contrarian is Mr. Jon R. Bauer (“Bauer”) and each of Contrarian and Bauer may be deemed to beneficially own the securities held by TCAB. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their
|
(3)
|
Richard VanderMass is a Managing Director of the business unit at Morgan Stanley & Co. LLC that holds the shares in the ordinary course of its business and as such may be deemed to have voting and dispositive power over the shares held by Morgan Stanley & Co. LLC. Richard VanderMass disclaims beneficial ownership of these shares. Morgan Stanley & Co. LLC, a registered broker-dealer, is a subsidiary of Morgan Stanley, a widely held reporting company under the Exchange Act. The number of shares beneficially owned includes 1,507 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Morgan Stanley that are exercisable within 60 days of
March 7, 2018
. The mailing address for Morgan Stanley & Co. LLC is 1585 Broadway, 2nd Floor, New York, NY 10036.
|
(4)
|
Monarch is the investment manager for Monarch Alternative Solutions Master Fund Ltd, Monarch Capital Master Partners III LP, MCP Holdings Master LP, Monarch Debt Recovery Master Fund Ltd and P Monarch Recovery Ltd. (together, the “Monarch Funds”). MDRA GP LP (“MDRA”) is the general partner of Monarch. Monarch GP LLC (“Monarch GP”) is the general partner of MDRA. Monarch, MDRA and Monarch GP each may be deemed to beneficially own the securities held by the Monarch Funds. Monarch, MDRA and Monarch GP each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. Joseph Citarrella, a Managing Principle of Monarch, is a member of the Board. Mr. Citarrella disclaims beneficial ownership of any such securities. The business address for each of the Monarch Funds is c/o Monarch Alternative Capital LP, 535 Madison Avenue, New York, NY 10022.
|
(5)
|
Each of Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes is a Manager of J.P. Morgan Securities LLC (“JPM”), a Delaware limited liability company, and as such may be deemed to have voting and dispositive power over the shares held by JPM. Each of Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes disclaims beneficial ownership of the shares. JPM is a broker-dealer registered pursuant to Section 15 of the Exchange Act. The number of shares beneficially owned includes 53,707 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by JPM that are exercisable within 60 days of
March 7, 2018
. The business address for each of JPM, Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes is 383 Madison Avenue, 3rd Floor, New York, New York 10179.
|
(6)
|
Reflects accounts managed by direct or indirect subsidiaries of FMR LLC. Abigail P. Johnson is a Director, the Vice Chairman, the Chief Executive Officer and the President of FMR LLC. Members of the Johnson family, including Abigail P. Johnson, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders’ voting agreement under which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares and the execution of the shareholders’ voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR LLC. Neither FMR LLC nor Abigail P. Johnson has the sole power to vote or direct the voting of the shares owned directly by the various investment companies registered under the Investment Company Act (“Fidelity Funds”) advised by Fidelity Management & Research Company (“FMR Co”), a wholly owned subsidiary of FMR LLC, which power resides with the Fidelity Funds’ Boards of Trustees. Fidelity Management & Research Company carries out the voting of the shares under written guidelines established by the Fidelity Funds’ Boards of Trustees. The business address of Fidelity Summer Street Trust: Fidelity Capital & Income Fund, Variable Insurance Products Fund: Strategic Income Portfolio, Fidelity School Street Trust: Fidelity Strategic Income Fund and Fidelity Advisor Series II: Fidelity Advisor Strategic Income Fund are 245 Summer Street, Boston, MA 02210. The Fidelity Funds are affiliates of a registered broker-dealer.
|
(7)
|
Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
March 7, 2018
, upon any departure from the Board.
|
(8)
|
Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
March 7, 2018
, upon any departure from the Board.
|
(9)
|
Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
March 7, 2018
, upon any departure from the Board.
|
•
|
an affiliate of us - a party that, directly or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with us;
|
•
|
a trust for the benefit of employees that is managed by or under the trusteeship of management;
|
•
|
an owner of record or known beneficial owner of more than 5% of the voting interest of us;
|
•
|
a member of our management including people with authority and responsibility for planning, directing and controlling our activities. Management includes members of the Board, Chief Executive Officer, Chief Financial Officer, General Counsel, Vice Presidents and persons in charge of principal business units and business functions, and any other persons who perform similar business or policymaking functions. If a director or member of management is also a director of another entity, the entities are considered related when they are both under the control or significant influence of that individual;
|
•
|
any family member, including spouses, brothers, sisters, parents, children and spouses of these persons who might control or influence a principal owner or member of management or who might be controlled or influenced by a principal owner or member of management because of a family relationship; or
|
•
|
other parties with which we may deal if one party can control or significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. The ability to exercise significant influence may be indicated in several ways, such as representation on the Board, participating in policy-making processes, material inter-company transactions, interchange of managerial personnel, or technology dependency.
|
|
Page
|
Report of Independent Registered Public Accounting Firm
|
|
Consolidated Statements of Operations
|
|
Consolidated Balance Sheets
|
|
Consolidated Statements of Stockholders’/Members’ Equity (Deficit)
|
|
Consolidated Statements of Cash Flows
|
|
Notes to Consolidated Financial Statements
|
|
Supplemental Financial Information
|
|
Supplemental Selected Quarterly Financial Information (Unaudited)
|
|
Supplemental Oil and Natural Gas Information
|
Exhibit
Number
|
|
Description of Exhibit
|
2.1
|
|
|
3.1
|
|
|
3.2
|
|
|
3.3
|
|
|
4.1
|
|
|
10.1
|
|
|
10.2
|
|
|
10.3
|
|
10.4
|
|
|
10.5
|
|
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.9*
|
|
|
10.10*
|
|
|
10.11*
|
|
|
10.12*
|
|
|
10.13*
|
|
|
10.14*
|
|
Vanguard Natural Resources, Inc. Management Incentive Plan (incorporated by reference to Exhibit 10.13 to our Quarterly Report on Form 10-Q filed November 9, 2017)
|
10.15**
|
|
|
10.16*
|
|
|
10.17*
|
|
|
21.1**
|
|
|
23.1**
|
|
|
23.2**
|
|
|
24.1
|
|
|
31.1**
|
|
|
31.2**
|
|
|
32.1**
|
|
|
32.2**
|
|
|
99.1**
|
|
|
99.2
|
|
|
101.INS**
|
|
XBRL Instance Document
|
101.SCH**
|
|
XBRL Schema Document
|
101.CAL**
|
|
XBRL Calculation Linkbase Document
|
101.DEF**
|
|
XBRL Definition Linkbase Document
|
101.LAB**
|
|
XBRL Label Linkbase Document
|
101.PRE**
|
|
XBRL Presentation Linkbase Document
|
**
|
Provided herewith.
|
VANGUARD NATURAL RESOURCES, INC.
|
|||||
|
|
/s/ R. Scott Sloan
|
|||
|
R. Scott Sloan
|
||||
|
President and Chief Executive Officer
|
March 21, 2018
|
/s/ R. Scott Sloan
|
|
R. Scott Sloan
|
|
President, Chief Executive Officer and Director
|
|
(Principal Executive Officer)
|
|
|
March 21, 2018
|
/s/ Ryan Midgett
|
|
Ryan Midgett
|
|
Chief Financial Officer
|
|
(Principal Financial Officer)
|
|
|
March 21, 2018
|
/s/ Patty Avila-Eady
|
|
Patty Avila-Eady
|
|
Chief Accounting Officer
|
|
(Principal Accounting Officer)
|
|
|
March 21, 2018
|
/s/ Joseph Citarrella
|
|
Joseph Citarrella
|
|
Chairman of the Board of Directors
|
|
|
March 21, 2018
|
/s/ Randall M. Albert
|
|
Randall M. Albert
|
|
Director
|
|
|
March 21, 2018
|
/s/ Michael Alexander
|
|
Michael Alexander
|
|
Director
|
|
|
March 21, 2018
|
/s/ W. Greg Dunlevy
|
|
W. Greg Dunlevy
|
|
Director
|
|
|
March 21, 2018
|
/s/ Graham Morris
|
|
Graham Morris
|
|
Director
|
|
|
March 21, 2018
|
/s/ Joseph Hurliman Jr.
|
|
Joseph Hurliman Jr.
|
|
Director
|
|
|
Place of
|
|
|
|
Percentage
|
|
|
Entity Name
|
|
Incorporation
|
|
Owner(s)
|
|
Ownership
|
|
|
|
|
|
|
|
|
|
|
|
Vanguard Natural Gas, LLC
|
|
Kentucky
|
|
Vanguard Natural Resources, Inc.
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
VNR Holdings, LLC
|
|
Delaware
|
|
Vanguard Natural Gas, LLC
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Vanguard Operating, LLC
|
|
Delaware
|
|
Vanguard Natural Gas, LLC
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Energy Acquisition Co. II, Inc.
|
|
Delaware
|
|
Vanguard Operating, LLC
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Energy Upstream Development Company II, Inc.
|
|
Delaware
|
|
Eagle Rock Energy Acquisition Co. II, Inc.
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Acquisition Partnership II, L.P.
|
|
Delaware
|
|
Vanguard Operating, LLC
(1)
|
|
95
|
|
%
|
|
|
|
|
Eagle Rock Energy Upstream Development Company II, Inc.
(1)
|
|
5
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Energy Acquisition Co., Inc.
|
|
Delaware
|
|
Vanguard Operating, LLC
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Energy Upstream Development Company, Inc.
|
|
Delaware
|
|
Eagle Rock Energy Acquisition Co., Inc.
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Eagle Rock Acquisition Partnership, L.P.
|
|
Delaware
|
|
Vanguard Operating, LLC
(2)
|
|
95
|
|
%
|
|
|
|
|
Eagle Rock Energy Upstream Development Company, Inc.
(2)
|
|
5
|
|
%
|
|
|
|
|
|
|
|
|
|
Escambia Operating Co. LLC
|
|
Delaware
|
|
Vanguard Operating, LLC
|
|
100
|
|
%
|
|
|
|
|
|
|
|
|
|
Escambia Asset Co. LLC
|
|
Delaware
|
|
Vanguard Operating, LLC
|
|
100
|
|
%
|
1.
|
I have reviewed this Annual Report on Form 10-K of Vanguard Natural Resources, Inc. (“the registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ R. Scott Sloan
|
|
R. Scott Sloan
|
|
|
|
President and Chief Executive Officer
|
|
(Principal Executive Officer)
|
|
Vanguard Natural Resources, LLC
|
1.
|
I have reviewed this Annual Report on Form 10-K of Vanguard Natural Resources, Inc. (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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a.
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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b.
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date: March 21, 2018
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/s/ Ryan Midgett
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Ryan Midgett
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Chief Financial Officer
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(Principal Financial Officer)
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Vanguard Natural Resources, LLC
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(1)
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the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ R. Scott Sloan
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R. Scott Sloan
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President and Chief Executive Officer
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(Principal Executive Officer)
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March 21, 2018
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(1)
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the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ Ryan Midgett
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Ryan Midgett
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Chief Financial Officer
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(Principal Financial Officer)
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March 21, 2018
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