(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, 2018
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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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x
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
x
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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
o
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No
x
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Yes
x
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No
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Caption
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•
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our ability to continue as a going concern;
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•
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our ability to meet our liquidity needs and service our indebtedness;
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•
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our ability to access the public capital markets;
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•
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risks and uncertainties associated with the 2019 Chapter 11 Cases (as defined herein) process described below, including our inability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring transaction, including a sale of all or substantially all of our assets;
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•
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inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our 2019 Bankruptcy Petitions (as defined herein);
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•
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our ability to obtain the approval of the Bankruptcy Court (as defined herein) with respect to motions or other requests made to the Bankruptcy Court in the 2019 Chapter 11 Cases (as defined herein), including maintaining strategic control as debtor-in-possession;
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•
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our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
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•
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the effects of the 2019 Bankruptcy Petitions on the Company and on the interests of various constituents, including holders of our Common Stock (as defined herein);
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•
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Bankruptcy Court rulings in the 2019 Chapter 11 Cases and the outcome of the 2019 Chapter 11 Cases in general;
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•
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the outcome of all other pending litigation;
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•
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the length of time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;
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•
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risks associated with third party motions in the 2019 Chapter 11 Cases, which may interfere with our ability to confirm and consummate a plan of reorganization;
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•
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the potential adverse effects of the 2019 Chapter 11 Cases on our liquidity and results of operations;
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•
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increased advisory costs to execute a reorganization;
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•
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risks relating to any of our unforeseen liabilities;
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•
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declines in oil, NGLs or natural gas prices;
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•
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the level of success in exploration, development and production activities;
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•
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adverse weather conditions that may negatively impact development or production activities;
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•
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the timing of exploitation and development expenditures;
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•
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inaccuracies of reserve estimates or assumptions underlying them;
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•
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revisions to reserve estimates as a result of changes in oil, natural gas and NGLs prices;
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•
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impacts to financial statements as a result of impairment write-downs;
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•
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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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•
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ability to regain compliance with restrictive covenants contained in the agreements governing our indebtedness that may adversely affect operational flexibility and comply with covenants in such agreements;
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•
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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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•
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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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compliance with applicable laws, rules and regulations;
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•
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the impact of the OTC Markets Group Inc.’s downgrade of our Common Stock and warrants to the OTC Pink (as defined herein) from the OTCQX U.S. tier;
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•
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federal, state and local initiatives and efforts relating to the regulation of development drilling and hydraulic fracturing;
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•
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failure of properties to yield oil or natural gas in commercially viable quantities;
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•
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uninsured or underinsured losses resulting from oil and natural gas operations;
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•
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ability to access oil and natural gas markets due to market conditions or operational impediments;
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•
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the impact and costs of compliance with laws and regulations governing oil and natural gas operations;
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•
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ability to replace oil and natural gas reserves;
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•
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any loss of senior management or technical personnel;
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•
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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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•
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the costs and effects of litigation;
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•
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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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•
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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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•
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the Arkoma Basin in Oklahoma;
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•
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the Gulf Coast Basin in Texas, Louisiana and Alabama;
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•
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the Big Horn Basin in Wyoming and Montana;
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•
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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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•
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the Powder River Basin in Wyoming.
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•
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a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019;
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•
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a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under the Successor Credit Facility (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);
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•
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proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;
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•
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the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) 35 days after the entry of the interim DIP order, if the Bankruptcy Court has not entered the final DIP order on or prior to such date, (c) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (d) the occurrence of an Event of Default (subject to any cure periods), and (e) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases;
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•
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interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%, or the adjusted base rate plus 4.50% per annum;
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•
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in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s
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•
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the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;
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•
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the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10.0 million, prepayment events, events of default and other provisions; and
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•
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generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date.
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•
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$677.7 million
in unpaid principal with respect to the Revolving Loan (as defined herein),
$123.4 million
in unpaid principal with respect to the Term Loan (as defined herein), and approximately
$11.6 million
of interest, fees, and other expenses arising under or in connection with the Successor Credit Facility.
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•
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$80.7 million
in unpaid principal, plus interest, fees, and other expenses, arising in connection with the New Notes issued pursuant to that certain Amended and Restated Indenture, dated as of August 2, 2017, among Vanguard Natural Resources, Inc., the guarantors named therein and Delaware Trust Company, as trustee and collateral trustee (the “Amended and Restated Indenture”).
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2018 Net Production
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|||||||||||||
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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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37,255
|
|
|
348
|
|
|
693
|
|
|
43,503
|
|
|
293,658
|
|
|
$
|
268.0
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|
Piceance Basin
|
|
17,498
|
|
|
178
|
|
|
1,241
|
|
|
26,011
|
|
|
259,434
|
|
|
$
|
245.7
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|
Permian Basin
|
|
6,001
|
|
|
1,145
|
|
|
506
|
|
|
15,907
|
|
|
148,985
|
|
|
$
|
220.5
|
|
Arkoma Basin
|
|
13,569
|
|
|
8
|
|
|
168
|
|
|
14,629
|
|
|
119,761
|
|
|
$
|
80.1
|
|
Gulf Coast Basin
|
|
4,754
|
|
|
542
|
|
|
367
|
|
|
10,203
|
|
|
98,407
|
|
|
$
|
128.7
|
|
Big Horn Basin
|
|
209
|
|
|
797
|
|
|
98
|
|
|
5,578
|
|
|
90,845
|
|
|
$
|
165.9
|
|
Anadarko Basin
|
|
1,467
|
|
|
109
|
|
|
48
|
|
|
2,407
|
|
|
26,089
|
|
|
$
|
30.0
|
|
Wind River Basin
|
|
2,194
|
|
|
10
|
|
|
54
|
|
|
2,581
|
|
|
23,676
|
|
|
$
|
13.6
|
|
Powder River Basin
|
|
5,480
|
|
|
—
|
|
|
—
|
|
|
5,480
|
|
|
16,609
|
|
|
$
|
8.6
|
|
Williston Basin
(a)
|
|
—
|
|
|
6
|
|
|
—
|
|
|
37
|
|
|
—
|
|
|
$
|
—
|
|
Total
|
|
88,427
|
|
|
3,143
|
|
|
3,175
|
|
|
126,336
|
|
|
1,077,464
|
|
|
$
|
1,161.1
|
|
(a)
|
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”).
|
(b)
|
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)
|
34.7
|
|
|
Natural gas (Bcf)
|
689.4
|
|
|
NGLs (MMBbls)
|
30.0
|
|
|
Total (Bcfe)
|
1,077.5
|
|
|
Proved developed (Bcfe)
|
1,077.5
|
|
|
Proved developed reserves as % of total proved reserves
|
100
|
%
|
|
PV-10
(1)
|
$
|
1,161.1
|
|
Less: Future income taxes (discounted at 10%)
|
(95.4
|
)
|
|
Standardized Measure (in millions)
(2)
|
$
|
1,065.7
|
|
Representative Oil and Natural Gas Prices
(3)
:
|
|
|
|
Oil—WTI per Bbl
|
$
|
65.66
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|
Natural gas—Henry Hub per MMBtu
|
$
|
3.10
|
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NGLs—Volume-weighted average price per Bbl
|
$
|
26.57
|
|
(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.
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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
2018
, 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 12-month average price of oil per Bbl of
$65.66
. As of April 1, 2019, the WTI crude oil price per barrel was
$61.59
and the Henry Hub natural gas spot price per MMBtu was
$2.73
.
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|
|
Estimated Proved Developed
Reserve Quantities
|
|
PV-10 Value
(1)
|
||||||||||||
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|
Natural Gas
(Bcf)
|
|
Oil
(MMBbls)
|
|
NGLs
(MMBbls)
|
|
Total
(Bcfe)
|
|
Developed
|
||||||
Operating Basin
|
|
|
|
|
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|
|
|
|
(in millions)
|
||||||
Green River Basin
|
|
256.8
|
|
|
2.3
|
|
|
3.9
|
|
|
293.7
|
|
|
$
|
268.0
|
|
Piceance Basin
|
|
170.7
|
|
|
1.3
|
|
|
13.4
|
|
|
259.4
|
|
|
245.7
|
|
|
Permian Basin
|
|
51.5
|
|
|
11.5
|
|
|
4.8
|
|
|
149.0
|
|
|
220.5
|
|
|
Arkoma Basin
|
|
108.8
|
|
|
0.1
|
|
|
1.8
|
|
|
119.8
|
|
|
80.1
|
|
|
Gulf Coast Basin
|
|
44.2
|
|
|
5.6
|
|
|
3.4
|
|
|
98.4
|
|
|
128.7
|
|
|
Big Horn Basin
|
|
3.8
|
|
|
12.7
|
|
|
1.8
|
|
|
90.8
|
|
|
165.9
|
|
|
Anadarko Basin
|
|
17.1
|
|
|
1.1
|
|
|
0.4
|
|
|
26.1
|
|
|
30.0
|
|
|
Wind River Basin
|
|
19.8
|
|
|
0.1
|
|
|
0.5
|
|
|
23.7
|
|
|
13.6
|
|
|
Powder River Basin
|
|
16.6
|
|
|
—
|
|
|
—
|
|
|
16.6
|
|
|
8.6
|
|
|
Total
|
|
689.3
|
|
|
34.7
|
|
|
30.0
|
|
|
1,077.5
|
|
|
$
|
1,161.1
|
|
(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, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Pinedale (Green River Basin)
|
|
826
|
|
|
96,111
|
|
|
1,782
|
|
|
$
|
48.02
|
|
|
$
|
2.14
|
|
|
$
|
21.70
|
|
|
$
|
0.50
|
|
Mamm Creek (Piceance Basin)
|
|
484
|
|
|
43,878
|
|
|
3,394
|
|
|
$
|
41.05
|
|
|
$
|
1.98
|
|
|
$
|
14.31
|
|
|
$
|
0.58
|
|
All other fields
|
|
7,300
|
|
|
102,277
|
|
|
3,524
|
|
|
$
|
36.48
|
|
|
$
|
2.44
|
|
|
$
|
32.43
|
|
|
$
|
1.68
|
|
Total
|
|
8,610
|
|
|
242,266
|
|
|
8,700
|
|
|
$
|
37.33
|
|
|
$
|
2.24
|
|
|
$
|
23.16
|
|
|
$
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Average daily production calculated based on 365 days for
2018
and
2017
and 366 days for 2016. During 2018 and 2017, we divested certain oil and natural gas properties and related assets. As such, there is no production from these properties included from the closing date of the divestitures forward. During 2016, we also acquired certain oil and natural gas properties and related assets. The production of these properties are included from the closing date of the acquisition forward.
|
(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 for the years ended December 31, 2018 and December 31, 2017, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - The Year Ended December 31,
2018
(Successor) Compared to The Five Months Ended December 31,
2017
(Successor) and the Seven Months Ended July 31, 2017 (Predecessor).”
|
(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
|
|
2,733
|
|
|
304
|
|
|
1
|
|
|
—
|
|
|
2,734
|
|
|
304
|
|
Piceance Basin
|
|
1,044
|
|
|
932
|
|
|
—
|
|
|
—
|
|
|
1,044
|
|
|
932
|
|
Permian Basin
|
|
780
|
|
|
469
|
|
|
2,548
|
|
|
771
|
|
|
3,328
|
|
|
1,240
|
|
Arkoma Basin
|
|
770
|
|
|
167
|
|
|
8
|
|
|
2
|
|
|
778
|
|
|
169
|
|
Gulf Coast Basin
|
|
696
|
|
|
237
|
|
|
53
|
|
|
26
|
|
|
749
|
|
|
263
|
|
Big Horn Basin
|
|
16
|
|
|
11
|
|
|
267
|
|
|
185
|
|
|
283
|
|
|
196
|
|
Anadarko Basin
|
|
521
|
|
|
69
|
|
|
263
|
|
|
13
|
|
|
784
|
|
|
82
|
|
Wind River Basin
|
|
134
|
|
|
125
|
|
|
7
|
|
|
7
|
|
|
141
|
|
|
132
|
|
Powder River Basin
|
|
489
|
|
|
302
|
|
|
—
|
|
|
—
|
|
|
489
|
|
|
302
|
|
Total
|
|
7,183
|
|
|
2,616
|
|
|
3,147
|
|
|
1,004
|
|
|
10,330
|
|
|
3,620
|
|
|
|
Developed Acreage
(1)
|
|
Undeveloped
Acreage
(2)
|
|
Total Acreage
|
||||||||||||
|
|
Gross
(3)
|
|
Net
(4)
|
|
Gross
(3)
|
|
Net
(4)
|
|
Gross
(3)
|
|
Net
(4)
|
||||||
Green River Basin
|
|
23,310
|
|
|
3,799
|
|
|
65,690
|
|
|
10,333
|
|
|
89,000
|
|
|
14,132
|
|
Piceance Basin
|
|
16,112
|
|
|
10,477
|
|
|
9,208
|
|
|
6,878
|
|
|
25,320
|
|
|
17,355
|
|
Permian Basin
|
|
310,700
|
|
|
215,497
|
|
|
24,418
|
|
|
15,340
|
|
|
335,118
|
|
|
230,837
|
|
Arkoma Basin
|
|
170,506
|
|
|
69,695
|
|
|
15,766
|
|
|
8,454
|
|
|
186,272
|
|
|
78,149
|
|
Gulf Coast Basin
|
|
125,687
|
|
|
49,956
|
|
|
22,966
|
|
|
13,331
|
|
|
148,653
|
|
|
63,287
|
|
Big Horn Basin
|
|
23,392
|
|
|
14,559
|
|
|
1,120
|
|
|
1,073
|
|
|
24,512
|
|
|
15,632
|
|
Anadarko Basin
|
|
67,867
|
|
|
18,310
|
|
|
31,938
|
|
|
8,363
|
|
|
99,805
|
|
|
26,673
|
|
Wind River Basin
|
|
6,913
|
|
|
5,492
|
|
|
64,383
|
|
|
41,297
|
|
|
71,296
|
|
|
46,789
|
|
Powder River Basin
|
|
65,106
|
|
|
37,868
|
|
|
49,181
|
|
|
28,998
|
|
|
114,287
|
|
|
66,866
|
|
Total
|
|
809,593
|
|
|
425,653
|
|
|
284,670
|
|
|
134,067
|
|
|
1,094,263
|
|
|
559,720
|
|
(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,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
Gross Development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|||
Green River Basin
|
|
131
|
|
|
138
|
|
|
120
|
|
Piceance Basin
|
|
14
|
|
|
—
|
|
|
—
|
|
Permian Basin
|
|
13
|
|
|
2
|
|
|
2
|
|
Arkoma Basin
|
|
12
|
|
|
6
|
|
|
5
|
|
Gulf Coast Basin
|
|
2
|
|
|
4
|
|
|
1
|
|
Big Horn Basin
|
|
1
|
|
|
4
|
|
|
—
|
|
Anadarko Basin
|
|
4
|
|
|
4
|
|
|
9
|
|
Powder River Basin
|
|
6
|
|
|
—
|
|
|
—
|
|
|
|
183
|
|
|
158
|
|
|
137
|
|
Dry
|
|
|
|
|
|
|
|||
Gulf Coast Basin
|
|
—
|
|
|
1
|
|
|
—
|
|
Total
|
|
183
|
|
|
159
|
|
|
137
|
|
|
|
|
|
|
|
|
|||
Net Development wells:
|
|
|
|
|
|
|
|||
Productive
|
|
|
|
|
|
|
|||
Green River Basin
|
|
17.8
|
|
|
20.7
|
|
|
15.2
|
|
Piceance Basin
|
|
13.9
|
|
|
—
|
|
|
—
|
|
Permian Basin
|
|
0.2
|
|
|
0.1
|
|
|
0.2
|
|
Arkoma Basin
|
|
0.7
|
|
|
0.5
|
|
|
0.1
|
|
Gulf Coast Basin
|
|
1.3
|
|
|
3.7
|
|
|
0.1
|
|
Big Horn Basin
|
|
0.6
|
|
|
1.0
|
|
|
—
|
|
Anadarko Basin
|
|
0.1
|
|
|
0.1
|
|
|
0.2
|
|
Powder River Basin
|
|
6.0
|
|
|
—
|
|
|
—
|
|
|
|
40.6
|
|
|
26.1
|
|
|
15.8
|
|
Dry
|
|
|
|
|
|
|
|||
Gulf Coast Basin
|
|
—
|
|
|
0.8
|
|
|
—
|
|
Total
|
|
40.6
|
|
|
26.9
|
|
|
15.8
|
|
Type of Arrangement
|
|
Pipeline System /Location
|
|
Deliverable Market
|
|
Gross Deliveries (MMBtu/d)
|
|
Term
|
Firm Transport
|
|
WIC Medicine Bow
|
|
Rocky Mountains
|
|
25,000
|
|
01/19 – 06/20
|
•
|
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. The extent of the hydrocarbon contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we cease operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. We do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require us to investigate and remediate any hydrocarbon contamination even while the gas plant remains in operation.
|
•
|
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.
|
•
|
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;
|
•
|
our ability to develop, file and complete a Chapter 11 plan of reorganization, particularly during the exclusivity period (i.e. in general, the period in which we have the exclusive right to file a Chapter 11 plan of reorganization);
|
•
|
our ability to obtain Bankruptcy Court, creditor and regulatory approval of a Chapter 11 plan of reorganization in a timely manner;
|
•
|
our ability to obtain Bankruptcy Court approval with respect to motions in the 2019 Chapter 11 Cases and the outcomes of Bankruptcy Court rulings and of the 2019 Chapter 11 Cases in general;
|
•
|
risks associated with third party motions in the 2019 Chapter 11 Cases, which may interfere with our business operations or our ability to propose and/or complete a Chapter 11 plan of reorganization;
|
•
|
increased costs related to the 2019 Chapter 11 Cases and related litigation;
|
•
|
a loss of, or a disruption in the materials or services received from, suppliers, contractors or service providers with whom we have commercial relationships;
|
•
|
potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees; and
|
•
|
significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations.
|
•
|
selling assets outside the ordinary course of business;
|
•
|
consolidating, merging, amalgamating, liquidating, dividing, winding up, dissolving or otherwise disposing of all or substantially all of its assets;
|
•
|
granting liens; and
|
•
|
financing its investments.
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree to and maintain price and production controls;
|
•
|
social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East and Venezuela, and armed conflict or terrorist attacks, whether or not in oil and natural gas producing regions;
|
•
|
the effect of energy conservation efforts;
|
•
|
shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas and NGLs so as to minimize emissions of carbon dioxide and methane GHGs;
|
•
|
volatility and trading patterns in the commodity-futures markets;
|
•
|
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, and the political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on oil, natural gas and NGLs prices;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
domestic and foreign governmental relations, regulation and taxation, including limits on the United States’ ability to export crude oil; and
|
•
|
trigger additional impairment charges to our oil and gas assets or other investments;
|
•
|
cause a significant decrease in the number of wells we drill on our acreage, thereby reducing our production and cash flows;
|
•
|
cause a reduction in cash flow, which would decrease funds available for capital expenditures employed to replace reserves and maintain or increase production;
|
•
|
cause a decrease in future undiscounted and discounted net cash flows from producing properties, possibly resulting in impairment expense that may be significant;
|
•
|
lower proved reserves, production and cash flow as certain reserves may no longer be economic to produce;
|
•
|
cause access to sources of capital, such as equity or long-term debt markets to be severely limited or unavailable; and
|
•
|
cause a reduction in the borrowing base on our Successor Credit Facility.
|
•
|
actual prices we receive for oil, natural gas and NGLs;
|
•
|
the amount and timing of actual production;
|
•
|
capital and operating expenditures;
|
•
|
the timing and success of development activities;
|
•
|
supply of and demand for oil, natural gas and NGLs; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
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.
|
•
|
the estimated quantities of our proved reserves;
|
•
|
the level of oil, natural gas and NGLs we are able to produce from existing wells;
|
•
|
our ability to transport our oil and natural gas to market;
|
•
|
the prices at which our oil, natural gas and NGLs are sold;
|
•
|
our ability to consummate planned asset divestitures;
|
•
|
the level of operating expenses;
|
•
|
our ability to acquire, locate and produce new reserves;
|
•
|
global credit and securities markets;
|
•
|
the ability and willingness of lenders and investors to provide capital and the cost of the capital; and
|
•
|
the impact of potential changes in our credit ratings.
|
•
|
unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;
|
•
|
data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
|
•
|
data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;
|
•
|
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
|
•
|
a cyber attack on third-party gathering, pipeline, or other transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;
|
•
|
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
|
•
|
a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market;
|
•
|
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
|
•
|
a cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;
|
•
|
a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
|
•
|
a cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
|
•
|
the high cost, shortages or delivery delays of equipment and services;
|
•
|
shortages in experienced labor;
|
•
|
the use of multi-well pad drilling that requires the drilling of all of the wells on a pad until any one of the pad’s wells can be brought into production;
|
•
|
risks associated with drilling horizontal wells and extended lateral lengths, such as deviating from the desired drilling zone or not running casing or tools consistently through the wellbore, particularly as lateral lengths get longer;
|
•
|
fracture stimulation accidents or failures;
|
•
|
surface access restrictions
|
•
|
reductions in oil, natural gas and NGLs prices;
|
•
|
limitations in the market for crude oil, natural gas and NGLs;
|
•
|
limited availability of financing at acceptable terms;
|
•
|
shortages of or delays in obtaining water for hydraulic fracturing operations;
|
•
|
unexpected operational events and conditions;
|
•
|
adverse weather conditions or events;
|
•
|
human errors, including actions by third-party operators of our properties;
|
•
|
facility or equipment malfunctions;
|
•
|
title deficiencies that can render a lease worthless;
|
•
|
compliance with environmental and other governmental or regulatory requirements, including any hydraulic fracturing regulations and other applicable regulations, and the failure to secure or delays in securing necessary regulatory, contractual and third-party approvals and permits;
|
•
|
unusual or unexpected geological formations;
|
•
|
loss of drilling fluid circulation;
|
•
|
formations with abnormal pressures or other irregularities;
|
•
|
environmental hazards, such as natural gas leaks, oil and produced water 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;
|
•
|
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
|
•
|
blowouts, craterings and explosions;
|
•
|
collapses of wellbore, casing or other tubulars;
|
•
|
uncontrollable flows of oil, natural gas or well fluids; and
|
•
|
crude oil, NGLs or natural gas gathering, transportation, processing, storage and export facility availability restrictions or limitations, or pipeline capacity curtailments.
|
•
|
our bankruptcy proceedings and the outcome of the 2019 Chapter 11 Cases;
|
•
|
our ability to continue as a going concern;
|
•
|
our downgrade to the OTC Pink;
|
•
|
lack of trading liquidity and limited trading volume;
|
•
|
our substantial indebtedness;
|
•
|
declines in production;
|
•
|
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;
|
•
|
the concentration of holdings of our Common Stock;
|
•
|
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 the 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.
|
|
As of December 31, 2018
|
||
Reserve Data:
|
|
||
Estimated net proved reserves:
|
|
||
Crude oil (MMBbls)
|
34.7
|
|
|
Natural gas (Bcf)
|
689.4
|
|
|
NGLs (MMBbls)
|
30.0
|
|
|
Total (Bcfe)
|
1,077.5
|
|
|
Proved developed (Bcfe)
|
1,077.5
|
|
|
Proved developed reserves as % of total proved reserves
|
100
|
%
|
|
PV-10
(1)
|
$
|
1,161.1
|
|
Less: Future income taxes (discounted at 10%)
|
(95.4
|
)
|
|
Standardized Measure (in millions)
(2)
|
$
|
1,065.7
|
|
Representative Oil and Natural Gas Prices
(3)
:
|
|
||
Oil—WTI per Bbl
|
$
|
65.66
|
|
Natural gas—Henry Hub per MMBtu
|
$
|
3.10
|
|
NGLs—Volume-weighted average price per Bbl
|
$
|
26.57
|
|
(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 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 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 read “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 average price for January through December
2018
, 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 12-month average price of oil per Bbl of
$65.66
. As of April 1, 2019, the WTI crude oil price per barrel was
$61.59
and the Henry Hub natural gas spot price per MMBtu was
$2.73
.
|
|
|
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, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Pinedale (Green River Basin)
|
|
826
|
|
|
96,111
|
|
|
1,782
|
|
|
$
|
48.02
|
|
|
$
|
2.14
|
|
|
$
|
21.70
|
|
|
$
|
0.50
|
|
Mamm Creek (Piceance Basin)
|
|
484
|
|
|
43,878
|
|
|
3,394
|
|
|
$
|
41.05
|
|
|
$
|
1.98
|
|
|
$
|
14.31
|
|
|
$
|
0.58
|
|
All other fields
|
|
7,300
|
|
|
102,277
|
|
|
3,524
|
|
|
$
|
36.48
|
|
|
$
|
2.44
|
|
|
$
|
32.43
|
|
|
$
|
1.68
|
|
Total
|
|
8,610
|
|
|
242,266
|
|
|
8,700
|
|
|
$
|
37.33
|
|
|
$
|
2.24
|
|
|
$
|
23.16
|
|
|
$
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
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
|
|
(1)
|
Average daily production calculated based on 365 days for
2018
and
2017
and 366 days for 2016. During 2018 and 2017, we divested certain oil and natural gas properties and related assets. As such, there is no production from these properties included from the closing date of the divestitures forward. During 2016, we also acquired certain oil and natural gas
|
(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 read “Management’s Discussion and Analysis of Financial Condition-
Year Ended December 31, 2018
compared to
Year Ended December 31, 2017
” 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).
|
•
|
the Green River Basin in Wyoming;
|
•
|
the Piceance Basin in Colorado;
|
•
|
the Permian Basin in West Texas and New Mexico;
|
•
|
the Arkoma Basin in Oklahoma;
|
•
|
the Gulf Coast Basin in Texas, Louisiana and Alabama;
|
•
|
the Big Horn Basin in Wyoming and Montana;
|
•
|
the Anadarko Basin in Oklahoma and North Texas;
|
•
|
the Wind River Basin in Wyoming; and
|
•
|
the Powder River Basin in Wyoming.
|
|
2019
|
2020
|
2021
|
2022
|
2023
|
2024
(1)
|
Oil ($/Bbl)
|
$63.82
|
$60.45
|
$56.98
|
$54.77
|
$53.76
|
$53.44
|
Gas ($/MMBtu)
|
$2.84
|
$2.77
|
$2.68
|
$2.68
|
$2.75
|
$2.86
|
|
Net Oil (Bbls)
|
Net Gas (MMcf)
|
Net NGL (Bbls)
|
Net Bcfe
|
PV-10 (in thousands)
|
Reserve Report at 4Q18
|
34,721
|
689,354
|
29,965
|
1,077.5
|
$1,161.1
|
April 8, 2019 NYMEX Strip Price
|
32,278
|
655,872
|
28,541
|
1,020.8
|
$884.0
|
% Difference
|
(7)%
|
(5)%
|
(5)%
|
(5)%
|
(24)%
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
Year Ended
December 31, 2018
|
|
Five Months Ended
December 31, 2017 |
|
|
Seven Months Ended
July 31, 2017 |
|
Years Ended December 31,
|
||||||||||||
|
|
|
|
|
Combined
|
|
Predecessor
|
|||||||||||||
|
|
|
|
|
2017
|
|
2016
|
|||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil sales
|
$
|
166,797
|
|
|
$
|
72,557
|
|
|
|
$
|
97,496
|
|
|
$
|
170,053
|
|
|
$
|
169,955
|
|
Natural gas sales
|
210,398
|
|
|
96,236
|
|
|
|
113,587
|
|
|
209,823
|
|
|
174,263
|
|
|||||
Natural gas liquids sales
|
92,351
|
|
|
36,825
|
|
|
|
35,565
|
|
|
72,390
|
|
|
44,462
|
|
|||||
Oil, natural gas and NGLs sales
|
469,546
|
|
|
205,618
|
|
|
|
246,648
|
|
|
452,266
|
|
|
388,680
|
|
|||||
Net losses on commodity derivative contracts
|
(9,259
|
)
|
|
(55,857
|
)
|
|
|
(24,887
|
)
|
|
(80,744
|
)
|
|
(44,072
|
)
|
|||||
Total revenues and losses on derivatives
|
$
|
460,287
|
|
|
$
|
149,761
|
|
|
|
$
|
221,761
|
|
|
$
|
371,522
|
|
|
$
|
344,608
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
136,721
|
|
|
60,976
|
|
|
|
87,092
|
|
|
148,068
|
|
|
159,672
|
|
|||||
Transportation, gathering, processing and compression
|
39,919
|
|
|
19,202
|
|
|
|
—
|
|
|
19,202
|
|
|
—
|
|
|||||
Production and other taxes
|
39,035
|
|
|
13,145
|
|
|
|
21,186
|
|
|
34,331
|
|
|
38,637
|
|
|||||
Depreciation, depletion, amortization and accretion
|
150,121
|
|
|
71,321
|
|
|
|
58,384
|
|
|
129,705
|
|
|
149,790
|
|
|||||
Impairment of oil and natural gas properties
|
29,706
|
|
|
47,640
|
|
|
|
—
|
|
|
47,640
|
|
|
494,270
|
|
|||||
Impairment of goodwill
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
252,676
|
|
|||||
Exploration expense
|
2,214
|
|
|
1,365
|
|
|
|
—
|
|
|
1,365
|
|
|
—
|
|
|||||
Selling, general and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Non-cash compensation
|
2,283
|
|
|
81
|
|
|
|
5,797
|
|
|
5,878
|
|
|
10,183
|
|
|||||
Other (excluding non-cash compensation)
|
43,557
|
|
|
21,577
|
|
|
|
23,013
|
|
|
44,590
|
|
|
41,335
|
|
|||||
Total costs and expenses
|
$
|
443,556
|
|
|
$
|
235,307
|
|
|
|
$
|
195,472
|
|
|
$
|
430,779
|
|
|
$
|
1,146,563
|
|
Other income and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
(62,900
|
)
|
|
$
|
(24,204
|
)
|
|
|
$
|
(35,276
|
)
|
|
$
|
(59,480
|
)
|
|
$
|
(95,367
|
)
|
Net gains (losses) on interest rate derivative contracts
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
30
|
|
|
$
|
30
|
|
|
$
|
(2,867
|
)
|
Net gain (loss) on acquisitions of oil and natural gas properties
|
$
|
4,687
|
|
|
$
|
4,450
|
|
|
|
$
|
—
|
|
|
$
|
4,450
|
|
|
$
|
(4,979
|
)
|
Gain on extinguishment of debt
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
89,714
|
|
Other
|
$
|
1,388
|
|
|
$
|
510
|
|
|
|
$
|
783
|
|
|
$
|
1,293
|
|
|
$
|
447
|
|
Reorganization items
|
$
|
(3,651
|
)
|
|
$
|
(6,488
|
)
|
|
|
$
|
908,485
|
|
|
$
|
901,997
|
|
|
$
|
—
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Combined
|
||||||||||
|
|
Year Ended December 31, 2018
|
|
Five Months Ended
December 31, 2017 |
|
|
Seven Months Ended
July 31, 2017
|
|
Year Ended December 31, 2017
|
||||||||
|
|
|
|
|
|
||||||||||||
Average realized prices, excluding hedging:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
53.08
|
|
|
$
|
47.79
|
|
|
|
$
|
43.33
|
|
|
$
|
45.13
|
|
Natural Gas (Price/Mcf)
|
|
$
|
2.38
|
|
|
$
|
2.49
|
|
|
|
$
|
2.05
|
|
|
$
|
2.23
|
|
NGLs (Price/Bbl)
|
|
$
|
29.08
|
|
|
$
|
27.70
|
|
|
|
$
|
17.87
|
|
|
$
|
21.81
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average realized prices, including hedging
(1)
:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
37.33
|
|
|
$
|
40.97
|
|
|
|
$
|
43.34
|
|
|
$
|
42.38
|
|
Natural Gas (Price/Mcf)
|
|
$
|
2.24
|
|
|
$
|
2.62
|
|
|
|
$
|
2.05
|
|
|
$
|
2.28
|
|
NGLs (Price/Bbl)
|
|
$
|
23.16
|
|
|
$
|
22.62
|
|
|
|
$
|
17.87
|
|
|
$
|
19.77
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Price/Bbl)
|
|
$
|
64.49
|
|
|
$
|
52.69
|
|
|
|
$
|
49.72
|
|
|
$
|
50.88
|
|
Natural Gas (Price/Mcf)
|
|
$
|
3.07
|
|
|
$
|
2.95
|
|
|
|
$
|
3.22
|
|
|
$
|
3.11
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total production volumes:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
|
3,143
|
|
|
1,518
|
|
|
|
2,250
|
|
|
3,768
|
|
||||
Natural Gas (MMcf)
|
|
88,427
|
|
|
38,634
|
|
|
|
55,375
|
|
|
94,009
|
|
||||
NGLs (MBbls)
|
|
3,176
|
|
|
1,329
|
|
|
|
1,990
|
|
|
3,319
|
|
||||
Combined (MMcfe)
|
|
126,337
|
|
|
55,719
|
|
|
|
80,814
|
|
|
136,533
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Bbls/day)
|
|
8,610
|
|
|
9,923
|
|
|
|
10,613
|
|
|
10,324
|
|
||||
Natural Gas (Mcf/day)
|
|
242,266
|
|
|
252,512
|
|
|
|
261,201
|
|
|
257,558
|
|
||||
NGLs (Bbls/day)
|
|
8,700
|
|
|
8,688
|
|
|
|
9,387
|
|
|
9,094
|
|
||||
Combined (Mcfe/day)
|
|
346,128
|
|
|
364,177
|
|
|
|
381,198
|
|
|
374,063
|
|
(1)
|
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.
|
•
|
a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019;
|
•
|
a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under Vanguard Natural Resources, Inc.’s (the “Company”) Credit Agreement (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);
|
•
|
proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;
|
•
|
the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) 35 days after the entry of the interim DIP order, if the Bankruptcy Court has not entered the final DIP order on or prior to such date, (c) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (d) the occurrence of an Event of Default (subject to any cure periods), and (e) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases.
|
•
|
interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%, or the adjusted base rate plus 4.50% per annum;
|
•
|
in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the New Money Facility, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;
|
•
|
the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all
|
•
|
the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10.0 million, prepayment events, events of default and other provisions; and
|
•
|
generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date.
|
|
|
Successor
|
|
|
Predecessor
|
|
||||||||
|
|
Year Ended December 31, 2018
|
|
Five Months Ended
December 31, 2017 |
|
|
Seven Months Ended
July 31, 2017 |
|
||||||
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|||||||||
Net cash provided by operating activities
|
|
$
|
84.9
|
|
|
$
|
16.6
|
|
|
|
$
|
80.7
|
|
|
Net cash provided by (used in) investing activities
|
|
$
|
(30.7
|
)
|
|
$
|
(29.5
|
)
|
|
|
$
|
76.8
|
|
|
Net cash used in financing activities
|
|
$
|
(26.2
|
)
|
|
$
|
(33.1
|
)
|
|
|
$
|
(151.5
|
)
|
|
•
|
$677.7 million
in unpaid principal with respect to the Revolving Loan,
$123.4 million
in unpaid principal with respect to the Term Loan, and approximately
$11.6 million
of interest, fees, and other expenses arising under or in connection with the Successor Credit Facility.
|
•
|
$80.7 million
in unpaid principal, plus interest, fees, and other expenses, arising in connection with the New Notes issued pursuant to the Amended and Restated Indenture.
|
Year
|
|
Required Payments
|
||
2019
|
|
$
|
1,250
|
|
2020
|
|
1,250
|
|
|
2021 through Maturity date
|
|
120,938
|
|
(i)
|
the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available, determined as of the last day of the fiscal quarter ending in the following periods:
|
Period
|
|
Ratio
|
December 31, 2018
|
|
5.50:1.0
|
March 31, 2019
|
|
5.75:1.0
|
June 30, 2019
|
|
5.25:1.0
|
September 30, 2019
|
|
5.00:1.0
|
December 31, 2019 and March 31, 2020
|
|
4.75:1.0
|
June 30, 2020
|
|
4.50:1.0
|
September 30, 2020
|
|
4.25:1.0
|
December 31, 2020 and thereafter
|
|
4.00:1.0
|
(ii)
|
an asset coverage ratio calculated as PV-9 of proved reserves, including impact of hedges and strip prices to first lien debt, of not less than
1.25
to 1.00 as tested on each January 1 and July 1 of each year commencing with the first such date after August 1, 2017; and;
|
(iii)
|
a ratio, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending December 31, 2017, of current assets to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than
1.00
to 1.00.
|
Year
|
|
Percentage
|
|
2020
|
|
106.75
|
%
|
2021
|
|
104.50
|
%
|
2022
|
|
102.25
|
%
|
2023 and thereafter
|
|
100.00
|
%
|
•
|
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. 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;
|
|
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.
|
|
|
Payments Due by Year (in thousands)
|
||||||||||||||||||||||||||
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Management base salaries
|
|
$
|
1,305
|
|
|
$
|
1,305
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,610
|
|
Asset retirement obligations
(1)
|
|
3,775
|
|
|
4,141
|
|
|
4,288
|
|
|
4,519
|
|
|
4,685
|
|
|
121,800
|
|
|
143,208
|
|
|||||||
Derivative liabilities
|
|
12,617
|
|
|
3,158
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15,791
|
|
|||||||
Revolving Loan
(2)(6)
|
|
682,145
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
682,145
|
|
|||||||
Term Loan
(2)(6)
|
|
123,438
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
123,438
|
|
|||||||
New Notes and interest
(6)
|
|
83,017
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
83,017
|
|
|||||||
Operating leases
|
|
1,211
|
|
|
1,149
|
|
|
1,169
|
|
|
1,204
|
|
|
1,241
|
|
|
3,262
|
|
|
9,236
|
|
|||||||
Development commitments
(3)
|
|
28,507
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28,507
|
|
|||||||
Firm transportation and processing agreements
(4)
|
|
820
|
|
|
410
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,230
|
|
|||||||
Lease Financing Obligations
(5)
|
|
5,442
|
|
|
4,359
|
|
|
1,278
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,079
|
|
|||||||
Other future obligations
|
|
308
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
308
|
|
|||||||
Total
|
|
$
|
942,585
|
|
|
$
|
14,522
|
|
|
$
|
6,751
|
|
|
$
|
5,723
|
|
|
$
|
5,926
|
|
|
$
|
125,062
|
|
|
$
|
1,100,569
|
|
(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.
|
(6)
|
As a result of our debt covenant violations, we have classified our debt under our Revolving Loan, Term Loan and New Notes, as current at December 31, 2018.
|
•
|
Net interest expense;
|
•
|
Depreciation, depletion, amortization and accretion;
|
•
|
Impairment of oil and natural gas properties;
|
•
|
Exploration expense;
|
•
|
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;
|
•
|
Severance 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.
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
|
Year Ended December 31, 2018
|
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
Net income (loss) attributable to Vanguard stockholders/unitholders
|
|
$
|
(43,971
|
)
|
|
$
|
(111,410
|
)
|
|
|
$
|
900,298
|
|
|
$
|
(815,089
|
)
|
|
$
|
(1,883,174
|
)
|
|
$
|
64,345
|
|
Add: Net income attributable to non-controlling interest
|
|
226
|
|
|
132
|
|
|
|
13
|
|
|
82
|
|
|
—
|
|
|
—
|
|
||||||
Net income (loss)
|
|
(43,745
|
)
|
|
(111,278
|
)
|
|
|
900,311
|
|
|
(815,007
|
)
|
|
(1,883,174
|
)
|
|
64,345
|
|
||||||
Plus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
|
|
62,900
|
|
|
24,204
|
|
|
|
35,276
|
|
|
95,367
|
|
|
87,573
|
|
|
69,765
|
|
||||||
Depreciation, depletion, amortization and accretion
|
|
150,121
|
|
|
71,321
|
|
|
|
58,384
|
|
|
149,790
|
|
|
247,119
|
|
|
226,937
|
|
||||||
Impairment of oil and natural gas properties
|
|
29,706
|
|
|
47,640
|
|
|
|
—
|
|
|
494,270
|
|
|
1,842,317
|
|
|
234,434
|
|
||||||
Exploration expense
|
|
2,214
|
|
|
1,365
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Impairment of goodwill
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
252,676
|
|
|
71,425
|
|
|
—
|
|
||||||
Change in fair value of commodity derivative contracts
(a)
|
|
(71,007
|
)
|
|
39,543
|
|
|
|
24,894
|
|
|
309,326
|
|
|
61,627
|
|
|
(174,571
|
)
|
||||||
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period
(a)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
292
|
|
|
5,434
|
|
|
—
|
|
||||||
Fair value of derivative contracts acquired that apply to contracts settled during the period
(a)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
15,285
|
|
|
44,761
|
|
|
21,306
|
|
||||||
Fair value of restructured derivative contracts
(a)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(69,515
|
)
|
|
—
|
|
||||||
Cash settlements paid on termination of derivative
contracts
(b)
|
|
—
|
|
|
4,140
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net (gains) losses on interest rate derivative contracts
(c)
|
|
—
|
|
|
—
|
|
|
|
(30
|
)
|
|
2,867
|
|
|
(153
|
)
|
|
1,933
|
|
||||||
Net (gain) loss on acquisitions and divestitures of oil and natural gas properties
|
|
(4,687
|
)
|
|
(4,450
|
)
|
|
|
—
|
|
|
4,979
|
|
|
(40,533
|
)
|
|
(34,523
|
)
|
||||||
Gain on extinguishment of debt
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(89,714
|
)
|
|
—
|
|
|
—
|
|
(b)
|
Adjusted EBITDA attributable to Vanguard stockholders 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.
|
(c)
|
Net gains (losses) on interest rate derivative contracts as shown on the consolidated statements operations is comprised of the following:
|
|
|
Predecessor
|
||||||||||||||
|
|
Seven Months Ended July 31, 2017
|
|
Years Ended December 31,
|
||||||||||||
|
|
|
|
|
|
|
|
|||||||||
|
|
|
2016
|
|
2015
|
|
2014
|
|||||||||
Change in fair value of interest rate derivative contracts
|
|
$
|
125
|
|
|
$
|
10,531
|
|
|
$
|
5,379
|
|
|
$
|
2,102
|
|
Net cash settlements paid on interest rate derivative contracts
|
|
$
|
(95
|
)
|
|
$
|
(13,398
|
)
|
|
$
|
(5,226
|
)
|
|
$
|
(4,035
|
)
|
Net gains (losses) on interest rate derivative contracts
|
|
$
|
30
|
|
|
$
|
(2,867
|
)
|
|
$
|
153
|
|
|
$
|
(1,933
|
)
|
(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.
|
|
|
|
Page
|
|
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
||
|
|
|
|
|
|
|
|
||
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
|
Year Ended December 31, 2018
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
||||||
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||
Oil sales
|
|
$
|
166,797
|
|
|
$
|
72,557
|
|
|
|
$
|
97,496
|
|
Natural gas sales
|
|
210,398
|
|
|
96,236
|
|
|
|
113,587
|
|
|||
Natural gas liquids sales
|
|
92,351
|
|
|
36,825
|
|
|
|
35,565
|
|
|||
Oil, natural gas and NGLs sales
|
|
469,546
|
|
|
205,618
|
|
|
|
246,648
|
|
|||
Net losses on commodity derivative contracts
|
|
(9,259
|
)
|
|
(55,857
|
)
|
|
|
(24,887
|
)
|
|||
Total revenues and losses on derivatives
|
|
460,287
|
|
|
149,761
|
|
|
|
221,761
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
|
||||||
Production:
|
|
|
|
|
|
|
|
||||||
Lease operating expenses
|
|
136,721
|
|
|
60,976
|
|
|
|
87,092
|
|
|||
Transportation, gathering, processing and compression
|
|
39,919
|
|
|
19,202
|
|
|
|
—
|
|
|||
Production and other taxes
|
|
39,035
|
|
|
13,145
|
|
|
|
21,186
|
|
|||
Depreciation, depletion, amortization and accretion
|
|
150,121
|
|
|
71,321
|
|
|
|
58,384
|
|
|||
Impairment of oil and natural gas properties
|
|
29,706
|
|
|
47,640
|
|
|
|
—
|
|
|||
Exploration expense
|
|
2,214
|
|
|
1,365
|
|
|
|
—
|
|
|||
Selling, general and administrative expenses
|
|
45,840
|
|
|
21,658
|
|
|
|
28,810
|
|
|||
Total costs and expenses
|
|
443,556
|
|
|
235,307
|
|
|
|
195,472
|
|
|||
Income (loss) from operations
|
|
16,731
|
|
|
(85,546
|
)
|
|
|
26,289
|
|
|||
Other income (expense):
|
|
|
|
|
|
|
|
||||||
Interest expense
|
|
(62,900
|
)
|
|
(24,204
|
)
|
|
|
(35,276
|
)
|
|||
Net gains on interest rate derivative contracts
|
|
—
|
|
|
—
|
|
|
|
30
|
|
|||
Net gain on divestiture of oil and natural gas
properties |
|
4,687
|
|
|
4,450
|
|
|
|
—
|
|
|||
Other
|
|
1,388
|
|
|
510
|
|
|
|
783
|
|
|||
Total other expense
|
|
(56,825
|
)
|
|
(19,244
|
)
|
|
|
(34,463
|
)
|
|||
Loss before reorganization items
|
|
(40,094
|
)
|
|
(104,790
|
)
|
|
|
(8,174
|
)
|
|||
Reorganization items
|
|
(3,651
|
)
|
|
(6,488
|
)
|
|
|
908,485
|
|
|||
Net income (loss)
|
|
(43,745
|
)
|
|
(111,278
|
)
|
|
|
900,311
|
|
|||
Less: Net income attributable to non-controlling
interests |
|
(226
|
)
|
|
(132
|
)
|
|
|
(13
|
)
|
|||
Net income (loss) attributable to Vanguard
stockholders/unitholders |
|
(43,971
|
)
|
|
(111,410
|
)
|
|
|
900,298
|
|
|||
Less: Distributions to Preferred unitholders
|
|
—
|
|
|
—
|
|
|
|
(2,230
|
)
|
|||
Net income (loss) attributable to Common
stockholders/Common and Class B unitholders |
|
$
|
(43,971
|
)
|
|
$
|
(111,410
|
)
|
|
|
$
|
898,068
|
|
Net income (loss) per Share/Unit:
|
|
|
|
|
|
|
|
||||||
Basic and diluted
|
|
$
|
(2.19
|
)
|
|
$
|
(5.55
|
)
|
|
|
$
|
6.84
|
|
Weighted average shares/units outstanding:
|
|
|
|
|
|
|
|
||||||
Common shares/units – basic and diluted
|
|
20,104
|
|
|
20,059
|
|
|
|
130,962
|
|
|||
Class B units – basic and diluted
|
|
—
|
|
|
—
|
|
|
|
420
|
|
|
Successor
|
||||||
|
2018
|
|
2017
|
||||
Assets
|
|
|
|
|
|
||
Current assets
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
33,538
|
|
|
$
|
2,762
|
|
Trade accounts receivable, net
|
62,073
|
|
|
67,248
|
|
||
Derivative assets
|
6,287
|
|
|
2,258
|
|
||
Restricted cash
|
4,450
|
|
|
7,255
|
|
||
Prepaid drilling costs
|
12,476
|
|
|
11,830
|
|
||
Other currents assets
|
5,663
|
|
|
3,934
|
|
||
Total current assets
|
124,487
|
|
|
95,287
|
|
||
Oil and natural gas properties
|
|
|
|
||||
Proved properties
|
1,567,903
|
|
|
1,560,552
|
|
||
Unproved properties
|
81,597
|
|
|
85,393
|
|
||
|
1,649,500
|
|
|
1,645,945
|
|
||
Accumulated depletion, amortization and impairment
|
(269,972
|
)
|
|
(112,553
|
)
|
||
Oil and natural gas properties, net – successful efforts
|
1,379,528
|
|
|
1,533,392
|
|
||
Other assets
|
|
|
|
||||
Derivative assets
|
6,766
|
|
|
—
|
|
||
Other assets
|
9,321
|
|
|
14,841
|
|
||
Total assets
|
$
|
1,520,102
|
|
|
$
|
1,643,520
|
|
Liabilities and equity
|
|
|
|
|
|||
Current liabilities
|
|
|
|
|
|||
Accounts payable:
|
|
|
|
||||
Trade
|
$
|
29,709
|
|
|
$
|
9,141
|
|
Accrued liabilities:
|
|
|
|
||||
Lease operating
|
13,140
|
|
|
13,560
|
|
||
Developmental capital
|
6,937
|
|
|
12,275
|
|
||
Interest
|
4,999
|
|
|
6,312
|
|
||
Production and other taxes
|
23,658
|
|
|
20,982
|
|
||
Other
|
12,175
|
|
|
9,005
|
|
||
Derivative liabilities
|
6,483
|
|
|
39,212
|
|
||
Oil and natural gas revenue payable
|
35,802
|
|
|
37,422
|
|
||
Long-term debt classified as current
|
879,181
|
|
|
—
|
|
||
Other current liabilities
|
9,091
|
|
|
12,175
|
|
||
Total current liabilities
|
1,021,175
|
|
|
160,084
|
|
||
Long-term debt
|
5,446
|
|
|
905,976
|
|
||
Derivative liabilities
|
—
|
|
|
27,483
|
|
||
Asset retirement obligations
|
139,433
|
|
|
151,717
|
|
||
Other long-term liabilities
|
523
|
|
|
732
|
|
||
Total liabilities
|
1,166,577
|
|
|
1,245,992
|
|
||
Commitments and contingencies (Note 10)
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
||||
Successor common stock ($0.001 par value, 50,000,000 shares authorized;
20,124,080 and 20,100,178 shares issued and outstanding at December 31, 2018 and
2017, respectively
|
20
|
|
|
20
|
|
||
Successor additional paid-in capital
|
508,886
|
|
|
506,640
|
|
||
Successor accumulated deficit
|
(155,381
|
)
|
|
(111,410
|
)
|
||
Total stockholders' equity
|
353,525
|
|
|
395,250
|
|
||
Non-controlling interest in subsidiary
|
—
|
|
|
2,278
|
|
||
Total stockholders' equity
|
353,525
|
|
|
397,528
|
|
||
Total liabilities and equity
|
$
|
1,520,102
|
|
|
$
|
1,643,520
|
|
(in thousands)
|
|
Cumulative Preferred Units
|
|
Common Units
|
|
Class B Units
|
|
Non-controlling Interest
|
|
Total Members’ Equity (Deficit)
|
||||||||||
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)
|
|
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
|
|
Net income (loss)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43,971
|
)
|
|
226
|
|
|
(43,745
|
)
|
|||||
Share-based compensation
|
|
24
|
|
|
—
|
|
|
2,246
|
|
|
—
|
|
|
—
|
|
|
2,246
|
|
|||||
Potato Hills cash distribution to non-controlling interest
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(427
|
)
|
|
(427
|
)
|
|||||
Disposition of non-controlling interest
|
|
|
|
|
|
|
|
|
|
(2,077
|
)
|
|
(2,077
|
)
|
|||||||||
Balance at December 31, 2018 (Successor)
|
|
20,124
|
|
|
$
|
20
|
|
|
$
|
508,886
|
|
|
$
|
(155,381
|
)
|
|
$
|
—
|
|
|
$
|
353,525
|
|
|
Successor
|
|
|
Predecessor
|
||||||||
(in thousands)
|
Year Ended December 31, 2018
|
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31,
2017
|
||||||
Operating activities
|
|
|
|
|
|
|
|
|||||
Net income (loss)
|
$
|
(43,745
|
)
|
|
$
|
(111,278
|
)
|
|
|
$
|
900,311
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, depletion, amortization and accretion
|
150,121
|
|
|
71,321
|
|
|
|
58,384
|
|
|||
Impairment of oil and natural gas properties
|
29,706
|
|
|
47,640
|
|
|
|
—
|
|
|||
Amortization of deferred financing costs
|
2,987
|
|
|
1,117
|
|
|
|
2,584
|
|
|||
Amortization of debt discount
|
—
|
|
|
—
|
|
|
|
348
|
|
|||
Non-cash reorganization cost
|
—
|
|
|
—
|
|
|
|
(937,956
|
)
|
|||
Compensation related items
|
2,246
|
|
|
81
|
|
|
|
5,429
|
|
|||
Net losses on commodity and interest rate derivative contracts
|
9,259
|
|
|
55,857
|
|
|
|
24,858
|
|
|||
Net cash settlements received (paid) on matured commodity derivative contracts
|
(80,266
|
)
|
|
(12,174
|
)
|
|
|
7
|
|
|||
Net cash settlements paid on matured interest rate derivative contracts
|
—
|
|
|
—
|
|
|
|
(95
|
)
|
|||
Cash received on termination of derivative contracts
|
—
|
|
|
(4,140
|
)
|
|
|
—
|
|
|||
Net gain on acquisitions and divestiture of oil and natural gas properties
|
(4,687
|
)
|
|
(4,450
|
)
|
|
|
—
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
||||||
Trade accounts receivable
|
6,430
|
|
|
(11,381
|
)
|
|
|
34,845
|
|
|||
Payables to affiliates
|
—
|
|
|
—
|
|
|
|
(895
|
)
|
|||
Premiums paid on commodity derivative contracts
|
—
|
|
|
—
|
|
|
|
(16
|
)
|
|||
Other current assets
|
(5,413
|
)
|
|
552
|
|
|
|
1,435
|
|
|||
Accounts payable and oil and natural gas revenue payable
|
20,724
|
|
|
(138
|
)
|
|
|
19,444
|
|
|||
Accrued expenses and other current liabilities
|
(3,728
|
)
|
|
(17,370
|
)
|
|
|
(27,018
|
)
|
|||
Other assets
|
1,240
|
|
|
945
|
|
|
|
(922
|
)
|
|||
Net cash provided by operating activities
|
84,874
|
|
|
16,582
|
|
|
|
80,743
|
|
|||
Investing activities
|
|
|
|
|
|
|
||||||
Additions to property and equipment
|
(203
|
)
|
|
(4
|
)
|
|
|
(102
|
)
|
|||
Additions to oil and natural gas properties
|
(74,835
|
)
|
|
(34,675
|
)
|
|
|
(25,694
|
)
|
|||
Proceeds from the sale of oil and natural gas properties
|
102,178
|
|
|
36,109
|
|
|
|
126,363
|
|
|||
Deposits and prepayments of oil and natural gas properties
|
(57,821
|
)
|
|
(30,956
|
)
|
|
|
(23,731
|
)
|
|||
Net cash provided by (used in) investing activities
|
(30,681
|
)
|
|
(29,526
|
)
|
|
|
76,836
|
|
|||
Financing activities
|
|
|
|
|
|
|
||||||
Proceeds from long-term debt
|
162,600
|
|
|
9,821
|
|
|
|
—
|
|
|||
Repayment of debt
|
(186,922
|
)
|
|
(42,118
|
)
|
|
|
(41,603
|
)
|
|||
Proceeds from Term Loan borrowings
|
—
|
|
|
—
|
|
|
|
125,000
|
|
|||
Repayment of debt under the predecessor credit facility
|
—
|
|
|
—
|
|
|
|
(500,266
|
)
|
|||
Proceeds from rights offerings and second lien investment
|
—
|
|
|
—
|
|
|
|
275,000
|
|
|||
Exercise of warrants
|
—
|
|
|
12
|
|
|
|
—
|
|
|||
Potato Hills distribution to non-controlling interest
|
(427
|
)
|
|
(128
|
)
|
|
|
(235
|
)
|
|||
Financing fees
|
(1,473
|
)
|
|
(691
|
)
|
|
|
(9,367
|
)
|
|||
Net cash used in financing activities
|
(26,222
|
)
|
|
(33,104
|
)
|
|
|
(151,471
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
Year Ended December 31, 2018
|
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31,
2017
|
||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
27,971
|
|
|
(46,048
|
)
|
|
|
6,108
|
|
|||
Cash, cash equivalents and restricted cash,
beginning of period
|
10,017
|
|
|
56,065
|
|
|
|
49,957
|
|
|||
Cash, cash equivalents and restricted cash,
end of period
|
$
|
37,988
|
|
|
$
|
10,017
|
|
|
|
$
|
56,065
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
||||||
Cash paid for interest
|
$
|
61,094
|
|
|
$
|
16,763
|
|
|
|
$
|
29,631
|
|
Non-cash financing and investing activities:
|
|
|
|
|
|
|
||||||
Asset retirement obligations, net
|
$
|
4,325
|
|
|
$
|
14,158
|
|
|
|
$
|
9,581
|
|
•
|
the Green River Basin in Wyoming;
|
•
|
the Piceance Basin in Colorado;
|
•
|
the Permian Basin in West Texas and New Mexico;
|
•
|
the Arkoma Basin in Oklahoma;
|
•
|
the Gulf Coast Basin in Texas, Louisiana and Alabama;
|
•
|
the Big Horn Basin in Wyoming and Montana;
|
•
|
the Anadarko Basin in Oklahoma and North Texas;
|
•
|
the Wind River Basin in Wyoming; and
|
•
|
the Powder River Basin in Wyoming.
|
1.
|
Going Concern Assessment
|
(a)
|
Basis of Presentation and Principles of Consolidation:
|
(b)
|
2019 Chapter 11 Proceedings:
|
(c)
|
New Pronouncements Recently Adopted:
|
(d)
|
New Pronouncements Issued But Not Yet Adopted:
|
(e)
|
Cash, Cash Equivalents and Restricted Cash:
|
|
|
Successor
|
||||||
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
|
$
|
33,538
|
|
|
$
|
2,762
|
|
Restricted cash
|
|
4,450
|
|
|
7,255
|
|
||
Total cash, cash equivalents and restricted cash
|
|
$
|
37,988
|
|
|
$
|
10,017
|
|
(f)
|
Accounts Receivable and Allowance for Doubtful Accounts:
|
(g)
|
Oil and Natural Gas Properties - Transition from Full Cost Method to Successful Efforts Accounting Method:
|
(h)
|
Asset Retirement Obligations:
|
(i)
|
Revenue Recognition and Gas Imbalances:
|
(j)
|
Concentrations of Credit Risk:
|
|
|
Successor
|
|
|
Predecessor
|
||
|
|
Year Ended December 31, 2018
|
|
Five Months
Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
Mieco, Inc.
|
|
14%
|
|
12%
|
|
|
11%
|
ConocoPhillips
|
|
5%
|
|
14%
|
|
|
13%
|
(k)
|
Use of Estimates:
|
(l)
|
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.
|
•
|
Basis swap contracts
- which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled
|
•
|
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.
|
(m)
|
Income Taxes:
|
(n)
|
Emergence from Voluntary Reorganization under Chapter 11 in 2017:
|
•
|
a super-priority senior secured revolving credit facility in the aggregate amount of up to
$65.0 million
(the “New Money Facility”), of which
$20.0 million
was drawn on April 4, 2019;
|
•
|
a “roll up” of
$65.0 million
of the outstanding principal amount of the revolving loans under Vanguard Natural Resources, Inc.’s (the “Company”) Credit Agreement (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);
|
•
|
proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;
|
•
|
the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) 35 days after the entry of the interim DIP order, if the Bankruptcy Court has not entered the final DIP order on or prior to such date, (c) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (d) the occurrence of an Event of Default (subject to any cure periods), and (e) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases.
|
•
|
interest will accrue at a rate per year equal to the LIBOR rate plus
5.50%
, or the adjusted base rate plus
4.50%
per annum;
|
•
|
in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to
1.0%
of the daily average of each lender’s unused commitment under the New Money Facility, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;
|
•
|
the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;
|
•
|
the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of
$10.0 million
, prepayment events, events of default and other provisions; and
|
•
|
generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date.
|
•
|
$677.7 million
in unpaid principal with respect to the Revolving Loan,
$123.4 million
in unpaid principal with respect to the Term Loan, and approximately
$11.6 million
of interest, fees, and other expenses arising under or in connection with the Successor Credit Facility.
|
•
|
$80.7 million
in unpaid principal, plus interest, fees, and other expenses, arising in connection with the New Notes issued pursuant to the Amended and Restated Indenture.
|
|
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
|
||||||
|
|
|
|
|
|
December 31,
|
||||||
Description
|
|
Interest Rate
|
|
Maturity Date
|
|
2018
|
|
2017
|
||||
Revolving Loan
|
|
Variable (1)
|
|
February 1, 2021
|
|
$
|
682,145
|
|
|
$
|
700,000
|
|
Term Loan
|
|
Variable (2)
|
|
May 1, 2021
|
|
123,438
|
|
|
124,688
|
|
||
New Notes
|
|
9.0%
|
|
February 15, 2024
|
|
80,722
|
|
|
80,722
|
|
||
Lease Financing Obligation
|
|
4.16%
|
|
August 10, 2020 (3)
|
|
10,454
|
|
|
15,205
|
|
||
Unamortized deferred financing costs
|
|
|
|
(7,124
|
)
|
|
(8,639
|
)
|
||||
Total Debt
|
|
|
|
|
|
$
|
889,635
|
|
|
$
|
911,976
|
|
Less:
|
|
|
|
|
|
|
|
|
||||
Long-term debt classified as current (4)
|
|
|
|
|
|
(879,181
|
)
|
|
—
|
|
||
Current portion of Term Loan
|
|
|
|
—
|
|
|
(1,250
|
)
|
||||
Current portion of Lease Financing Obligation
|
|
|
|
(5,008
|
)
|
|
(4,750
|
)
|
||||
Total long-term debt
|
|
|
|
|
|
$
|
5,446
|
|
|
$
|
905,976
|
|
(4)
|
Under ASC Topic 470,
“Debt,”,
as a result of our debt covenant violations, we have classified our debt under our Revolving Loan, Term Loan and New Notes, as current at December 31, 2018.
|
Year
|
|
Required Payments
|
||
2019
|
|
$
|
1,250
|
|
2020
|
|
1,250
|
|
|
2021 through Maturity date
|
|
120,938
|
|
(i)
|
the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available, determined as of the last day of the fiscal quarter ending in the following periods:
|
Period
|
|
Ratio
|
December 31, 2018
|
|
5.50:1.0
|
March 31, 2019
|
|
5.75:1.0
|
June 30, 2019
|
|
5.25:1.0
|
September 30, 2019
|
|
5.00:1.0
|
December 31, 2019 and March 31, 2020
|
|
4.75:1.0
|
June 30, 2020
|
|
4.50:1.0
|
September 30, 2020
|
|
4.25:1.0
|
December 31, 2020 and thereafter
|
|
4.00:1.0
|
(ii)
|
an asset coverage ratio calculated as PV-9 of proved reserves, including impact of hedges and strip prices to first lien debt, of not less than
1.25
to 1.00 as tested on each January 1 and July 1 of each year commencing with the first such date after August 1, 2017; and;
|
(iii)
|
a ratio, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending December 31, 2017, of current assets to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than
1.00
to 1.00.
|
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, 2019 - December 31, 2019
|
|
52,539,000
|
|
|
$
|
2.79
|
|
|
1,858,200
|
|
|
$
|
48.50
|
|
|
32,616,842
|
|
|
$
|
0.88
|
|
January 1, 2020 - December 31, 2020
|
|
47,227,500
|
|
|
$
|
2.75
|
|
|
1,393,800
|
|
|
$
|
49.53
|
|
|
—
|
|
|
$
|
—
|
|
|
|
Gas
|
|||||||
Contract Period
|
|
MMBtu
|
|
Weighted Avg. Basis Differential
($/MMBtu)
|
|
Pricing Index
|
|||
January 1, 2019 - December 31, 2019
|
|
21,210,000
|
|
|
$
|
(0.48
|
)
|
|
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
|
January 1, 2019 - December 31, 2019
|
|
5,475,000
|
|
|
$
|
(0.25
|
)
|
|
Enable East Gas and NYMEX Henry Hub Basis Differential
|
|
|
Oil
|
|||||||
Contract Period
|
|
Bbls
|
|
Weighted
Avg. Basis
Differential ($/Bbl)
|
|
Pricing Index
|
|||
January 1, 2019 - December 31, 2019
|
|
456,250
|
|
|
$
|
(5.78
|
)
|
|
WTI Midland and WTI Cushing Basis Differential
|
January 1, 2020 - December 31, 2020
|
|
366,000
|
|
|
$
|
(0.10
|
)
|
|
WTI Midland and WTI Cushing Basis Differential
|
January 1, 2019 - December 31, 2019
|
|
182,500
|
|
|
$
|
(20.40
|
)
|
|
WTI and WCS Basis Differential
|
|
|
Gas
|
Oil
|
|||||||||||||||||||
Contract Period
|
|
MMBtu
|
|
Floor Price
($/MMBtu)
|
|
Ceiling Price
($/MMBtu)
|
|
Bbls
|
|
Floor Price
($/Bbl)
|
|
Ceiling Price
($/Bbl)
|
||||||||||
January 1, 2019 - December 31, 2019
|
|
4,125,000
|
|
|
$
|
2.60
|
|
|
$
|
3.00
|
|
|
575,730
|
|
|
$
|
43.81
|
|
|
$
|
54.04
|
|
January 1, 2020 - December 31, 2020
|
|
5,490,000
|
|
|
$
|
2.60
|
|
|
$
|
3.00
|
|
|
659,340
|
|
|
$
|
44.17
|
|
|
$
|
55.00
|
|
January 1, 2021 - December 31, 2021
|
|
1,825,000
|
|
|
$
|
2.60
|
|
|
$
|
3.07
|
|
|
294,536
|
|
|
$
|
55.25
|
|
|
$
|
63.76
|
|
|
|
Successor
|
||||||||||
|
|
December 31, 2018
|
||||||||||
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
|
|
$
|
22,361
|
|
|
$
|
(9,308
|
)
|
|
$
|
13,053
|
|
Total derivative instruments
|
|
$
|
22,361
|
|
|
$
|
(9,308
|
)
|
|
$
|
13,053
|
|
|
|
|
|
|
|
|
||||||
Offsetting Derivative Liabilities:
|
|
Gross Amounts of Recognized Liabilities
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
Commodity price derivative contracts
|
|
$
|
(15,791
|
)
|
|
$
|
9,308
|
|
|
$
|
(6,483
|
)
|
Total derivative instruments
|
|
$
|
(15,791
|
)
|
|
$
|
9,308
|
|
|
$
|
(6,483
|
)
|
|
|
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
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
Year Ended December 31, 2018
|
|
Five Months Ended December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
||||||
Derivative liability at beginning of period, net
|
$
|
(64,437
|
)
|
|
$
|
(24,894
|
)
|
|
|
$
|
(125
|
)
|
Purchases
|
|
|
|
|
|
|
||||||
Net losses on commodity and interest rate derivative contracts
|
(9,259
|
)
|
|
(55,857
|
)
|
|
|
(24,857
|
)
|
|||
Settlements
|
|
|
|
|
|
|
||||||
Cash settlements paid (received) on matured commodity derivative contracts
|
80,266
|
|
|
12,174
|
|
|
|
(7
|
)
|
|||
Cash settlements paid on matured interest rate derivative contracts
|
—
|
|
|
—
|
|
|
|
95
|
|
|||
Termination of derivative contracts
|
—
|
|
|
4,140
|
|
|
|
—
|
|
|||
Derivative asset (liability) at end of period, net
|
$
|
6,570
|
|
|
$
|
(64,437
|
)
|
|
|
$
|
(24,894
|
)
|
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, 2018
|
||||||
|
|
Fair Value
Measurements
Using Level 2
|
|
Assets/Liabilities at Fair Value
|
||||
|
|
(in thousands)
|
||||||
Assets:
|
|
|
|
|
||||
Commodity price derivative contracts
|
|
$
|
13,053
|
|
|
$
|
13,053
|
|
Total derivative instruments
|
|
$
|
13,053
|
|
|
$
|
13,053
|
|
|
|
|
|
|
||||
Liabilities:
|
|
|
|
|
|
|
||
Commodity price derivative contracts
|
|
$
|
(6,483
|
)
|
|
$
|
(6,483
|
)
|
Total derivative instruments
|
|
$
|
(6,483
|
)
|
|
$
|
(6,483
|
)
|
|
|
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
|
)
|
Asset retirement obligations as of January 1, 2017 (Predecessor)
|
|
$
|
272,436
|
|
Liabilities added during the current period
|
|
555
|
|
|
Accretion expense
|
|
6,795
|
|
|
Retirements
|
|
(1,161
|
)
|
|
Liabilities related to assets divested
|
|
(10,107
|
)
|
|
Change in estimate
|
|
(29
|
)
|
|
Asset retirement obligation at July 31, 2017 (Predecessor)
|
|
268,489
|
|
|
Fresh-start adjustment
(1)
|
|
(123,320
|
)
|
|
Asset retirement obligation at July 31, 2017 (Successor)
|
|
145,169
|
|
|
Liabilities added during the current period
|
|
10,540
|
|
|
Accretion expense
|
|
3,975
|
|
|
Liabilities related to assets divested
|
|
(5,066
|
)
|
|
Retirements
|
|
(812
|
)
|
|
Change in estimate
|
|
3,618
|
|
|
Asset retirement obligation at December 31, 2017 (Successor)
|
|
157,424
|
|
|
Liabilities added during the current period
|
|
610
|
|
|
Accretion expense
|
|
9,295
|
|
|
Liabilities related to assets divested
|
|
(16,687
|
)
|
|
Retirements
|
|
(2,499
|
)
|
|
Change in estimate
|
|
(4,935
|
)
|
|
Asset retirement obligation at December 31, 2018 (Successor)
|
|
143,208
|
|
|
Less: current obligations
|
|
(3,775
|
)
|
|
Long-term asset retirement obligation at December 31, 2018 (Successor)
|
|
$
|
139,433
|
|
|
|
Demand Charges
|
||
|
|
(in thousands)
|
||
2019
|
|
$
|
820
|
|
2020
|
|
410
|
|
|
Total
|
|
$
|
1,230
|
|
|
|
Lease Payments
|
||
|
|
(in thousands)
|
||
2019
|
|
$
|
1,211
|
|
2020
|
|
1,149
|
|
|
2021
|
|
1,169
|
|
|
2022
|
|
1,204
|
|
|
2023
|
|
1,241
|
|
|
Thereafter
|
|
3,262
|
|
|
Total
|
|
$
|
9,236
|
|
|
|
Time-Based Restricted Stock Units
|
|
Weighted Average
Grant Date Fair Value
|
|||
Non-vested at December 31, 2017
|
|
7,500
|
|
|
$
|
19.50
|
|
Granted
|
|
277,071
|
|
|
$
|
16.62
|
|
Forfeited
|
|
(4,146
|
)
|
|
$
|
19.93
|
|
Vested
|
|
(35,929
|
)
|
|
$
|
16.80
|
|
Non-vested at December 31, 2018
|
|
244,496
|
|
|
$
|
16.62
|
|
|
|
TSR Performance RSU Replacement Awards
|
Modification Date
|
|
September 11, 2018
|
Remaining Performance period
|
|
2.31 years
|
VNR Closing Price
|
|
$5.40
|
VNR Beginning TSR Price
|
|
$19.00
|
Compounded Risk-Free Interest Rate (2.31-yr)
|
|
2.75%
|
VNR Historical Volatility (2.31-yr)
|
|
71.69%
|
Fair value of unit
|
|
$19.76
|
|
Successor
|
||||
|
Year Ended
December 31, 2018
|
|
Five Months Ended December 31, 2017
|
||
Federal statutory rate
|
21.00
|
%
|
|
35.00
|
%
|
Permanent items
|
6.03
|
%
|
|
(2.00
|
)%
|
Federal statutory rate change
|
—
|
%
|
|
(17.80
|
)%
|
State, net of federal tax benefit
|
0.96
|
%
|
|
3.00
|
%
|
Valuation allowance adjustments
|
(27.82
|
)%
|
|
(18.20
|
)%
|
Effective rate
|
0.17
|
%
|
|
—
|
%
|
|
Successor
|
||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||
Deferred tax assets:
|
|
|
|
||||
Asset retirement obligation
|
$
|
34,158
|
|
|
$
|
39,084
|
|
Net operating loss carryforwards
|
17,999
|
|
|
2,957
|
|
||
Interest carryforward
|
14,185
|
|
|
—
|
|
||
Investment in subsidiaries
|
5,781
|
|
|
4,827
|
|
||
Derivative instruments
|
—
|
|
|
7,655
|
|
||
Accrued liabilities
|
1,483
|
|
|
6,681
|
|
||
Bad debts
|
1,142
|
|
|
1,489
|
|
||
Other
|
702
|
|
|
31
|
|
||
Valuation allowance
|
(47,768
|
)
|
|
(35,447
|
)
|
||
Total deferred tax assets
|
27,682
|
|
|
27,277
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Oil & natural gas property
|
(24,664
|
)
|
|
(27,277
|
)
|
||
Derivative instruments
|
(3,018
|
)
|
|
—
|
|
||
Total deferred tax liabilities
|
(27,682
|
)
|
|
(27,277
|
)
|
||
Net deferred tax assets (liabilities)
|
$
|
—
|
|
|
$
|
—
|
|
|
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
|
||
Revolving Loan
|
$
|
730,000
|
|
Term Loan
|
125,000
|
|
|
New Notes
|
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
|
|
|
Revolving Loan 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)
|
|
|
|
|
|
|
|
|
|
|
||||||||
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 Revolving Loan 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 New Notes.
|
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 Revolving Loan and the New Notes 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 New Notes 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).
|
|
Predecessor
|
||
|
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
|
(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
|
$
|
908,485
|
|
|
|
Quarters Ended
|
||||||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Total
|
||||||||||
|
|
(in thousands, except per unit amounts)
|
||||||||||||||||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil, natural gas and NGLs sales
|
|
$
|
123,275
|
|
|
$
|
111,713
|
|
|
$
|
116,430
|
|
|
$
|
118,128
|
|
|
$
|
469,546
|
|
Net income (losses) on commodity derivative contracts
|
|
(18,585
|
)
|
|
(45,332
|
)
|
|
(30,887
|
)
|
|
85,545
|
|
|
(9,259
|
)
|
|||||
Total revenues
|
|
$
|
104,690
|
|
|
$
|
66,381
|
|
|
$
|
85,543
|
|
|
$
|
203,673
|
|
|
$
|
460,287
|
|
Total costs and expenses
(1)
|
|
$
|
106,369
|
|
|
$
|
104,751
|
|
|
$
|
101,243
|
|
|
$
|
101,487
|
|
|
$
|
413,850
|
|
Impairment of oil and natural gas properties
|
|
$
|
14,601
|
|
|
$
|
7,552
|
|
|
$
|
1,965
|
|
|
$
|
5,588
|
|
|
$
|
29,706
|
|
Interest expense
|
|
$
|
14,753
|
|
|
$
|
15,870
|
|
|
$
|
16,060
|
|
|
$
|
16,217
|
|
|
$
|
62,900
|
|
Net gain (losses) on divestitures of oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
4,900
|
|
|
$
|
1,747
|
|
|
$
|
(1,960
|
)
|
|
$
|
4,687
|
|
Reorganization items
|
|
$
|
(1,707
|
)
|
|
$
|
(610
|
)
|
|
$
|
(732
|
)
|
|
$
|
(602
|
)
|
|
$
|
(3,651
|
)
|
Net income (loss)
|
|
$
|
(32,591
|
)
|
|
$
|
(57,677
|
)
|
|
$
|
(32,096
|
)
|
|
$
|
78,619
|
|
|
$
|
(43,745
|
)
|
Net income (loss) attributable to non-controlling interest
|
|
$
|
93
|
|
|
$
|
96
|
|
|
$
|
37
|
|
|
$
|
—
|
|
|
$
|
226
|
|
Net income (loss) attributable to Vanguard stockholders
|
|
$
|
(32,684
|
)
|
|
$
|
(57,773
|
)
|
|
$
|
(32,133
|
)
|
|
$
|
78,619
|
|
|
$
|
(43,971
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss) per Common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Basic and diluted
|
|
$
|
(1.63
|
)
|
|
$
|
(2.87
|
)
|
|
$
|
(1.60
|
)
|
|
$
|
3.91
|
|
|
$
|
(2.19
|
)
|
|
|
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
|
)
|
(1)
|
Includes lease operating expenses, transportation, gathering, processing and compression, production and other taxes, depreciation, depletion, amortization and accretion, exploration expenses, and selling, general and administration expenses.
|
|
|
Successful Efforts Method
|
||||||
|
|
Successor
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in thousands)
|
||||||
Proved properties
|
|
$
|
1,567,903
|
|
|
1,560,552
|
|
|
Unproved properties
|
|
81,597
|
|
|
85,393
|
|
||
|
|
1,649,500
|
|
|
1,645,945
|
|
||
Aggregate accumulated depletion, amortization and impairment
|
|
(269,972
|
)
|
|
(112,553
|
)
|
||
Net capitalized costs
|
|
$
|
1,379,528
|
|
|
$
|
1,533,392
|
|
|
|
Successful Efforts Method
|
|
|
Full Cost Method
|
||||||||
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
|
Year Ended December 31, 2018
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
||||||
|
|
|
|
|
|||||||||
Development costs
|
|
124,865
|
|
|
79,246
|
|
|
|
46,315
|
|
|||
Total cost incurred
|
|
$
|
124,865
|
|
|
$
|
79,246
|
|
|
|
$
|
46,315
|
|
|
|
Gas (in MMcf)
|
|
Oil (in MBbls)
|
|
NGL (in MBbls)
|
|||
Net proved reserves
|
|
|
|
|
|
|
|
|
|
January 1, 2017
|
|
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
|
|
Revisions of previous estimates
|
|
(513,272
|
)
|
|
(80
|
)
|
|
(4,930
|
)
|
Extensions, discoveries and other
|
|
14,718
|
|
|
1,447
|
|
|
728
|
|
Purchases of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
|
(80,981
|
)
|
|
(2,474
|
)
|
|
(1,013
|
)
|
Production
|
|
(88,701
|
)
|
|
(3,143
|
)
|
|
(3,176
|
)
|
December 31, 2018
|
|
689,353
|
|
|
34,720
|
|
|
29,964
|
|
|
|
|
|
|
|
|
|||
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
831,479
|
|
|
34,257
|
|
|
31,381
|
|
December 31, 2018
|
|
689,353
|
|
|
34,720
|
|
|
29,964
|
|
|
|
|
|
|
|
|
|||
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
526,110
|
|
|
4,713
|
|
|
6,974
|
|
December 31, 2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
|
Year Ended
December 31, 2018
|
|
Five Months Ended
December 31, 2017
|
|
|
Seven Months Ended
July 31, 2017
|
||||||
|
|
|
|
|
|||||||||
|
|
(in thousands)
|
|
|
(in thousands)
|
||||||||
Production revenues
|
|
$
|
469,546
|
|
|
$
|
205,618
|
|
|
|
$
|
246,648
|
|
Production costs
(1)
|
|
(215,675
|
)
|
|
(93,323
|
)
|
|
|
(108,278
|
)
|
|||
Depreciation, depletion and amortization
|
|
(149,315
|
)
|
|
(70,826
|
)
|
|
|
(56,919
|
)
|
|||
Impairment of oil and natural gas properties
|
|
(29,706
|
)
|
|
(47,640
|
)
|
|
|
—
|
|
|||
Results of operations from producing activities
|
|
$
|
74,850
|
|
|
$
|
(6,171
|
)
|
|
|
$
|
81,451
|
|
(1)
|
Production cost includes lease operating expenses, transportation, gathering, processing and compression
|
|
|
2018
|
|
2017
|
||||
|
|
(in thousands)
|
||||||
Future cash inflows
|
|
$
|
4,308,231
|
|
|
$
|
5,514,270
|
|
Future production costs
|
|
(2,286,215
|
)
|
|
(2,634,887
|
)
|
||
Future development costs
|
|
(37,157
|
)
|
|
(554,807
|
)
|
||
Future net cash flows before income taxes
|
|
1,984,859
|
|
|
2,324,576
|
|
||
Future income taxes
(1)
|
|
(162,988
|
)
|
|
(232,912
|
)
|
||
Future net cash flows
|
|
1,821,871
|
|
|
2,091,664
|
|
||
10% annual discount for estimated timing of cash flows
|
|
(756,145
|
)
|
|
(1,018,036
|
)
|
||
Standardized measure of discounted future net cash flows
(2)
|
|
$
|
1,065,726
|
|
|
$
|
1,073,628
|
|
(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. See Note 13 of the Notes to the Consolidated Financial Statements for additional information about income taxes.
|
(2)
|
The 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)
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in thousands)
|
||||||
Sales and transfers, net of production costs
|
|
$
|
(251,921
|
)
|
|
$
|
(250,667
|
)
|
Net changes in prices and production costs
|
|
242,707
|
|
|
360,867
|
|
||
Extensions discoveries and improved recovery, less related costs
|
|
39,416
|
|
|
235,949
|
|
||
Changes in estimated future development costs
|
|
385,739
|
|
|
30,584
|
|
||
Previously estimated development costs incurred during the period
|
|
71,485
|
|
|
—
|
|
||
Revision of previous quantity estimates
|
|
(558,925
|
)
|
|
(55,606
|
)
|
||
Accretion of discount
|
|
130,654
|
|
|
85,377
|
|
||
Net change in income taxes
|
|
(95,378
|
)
|
|
(121,155
|
)
|
||
Sales of reserves in place
|
|
(85,439
|
)
|
|
(32,989
|
)
|
||
Change in production rates, timing and other
|
|
113,760
|
|
|
(32,501
|
)
|
||
Net change
|
|
$
|
(7,902
|
)
|
|
$
|
219,859
|
|
(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
|
54
|
President, Chief Executive Officer and Director
|
August 1, 2017
|
Randall M. Albert
|
61
|
Independent Director
|
September 26, 2017
|
Patrick J. Bartels, Jr.
|
43
|
Independent Director
|
February 1, 2019
|
W. Greg Dunlevy
|
63
|
Independent Director and Chairman
|
October 17, 2017
|
Joseph Hurliman Jr.
|
61
|
Independent Director
|
February 21, 2018
|
Andrew E. Schultz
|
64
|
Independent Director
|
February 8, 2019
|
L. Spencer Wells
|
48
|
Independent Director
|
February 1, 2019
|
Name
|
Age
|
Position with Vanguard
|
R. Scott Sloan
|
54
|
President, Chief Executive Officer and Director
|
Ryan Midgett
|
34
|
Chief Financial Officer
|
Jonathan C. Curth
|
36
|
General Counsel, Corporate Secretary, Compliance Officer and Vice President of Land
|
•
|
R. Scott Sloan, our former Executive Vice President and Chief Financial Officer and current President and Chief Executive Officer;
|
•
|
Ryan Midgett, our Chief Financial Officer;
|
•
|
Jonathan C. Curth, our General Counsel, Corporate Secretary, Compliance Officer and Vice President of Land;
|
•
|
Britt Pence, our former Executive Vice President of Operations; and
|
•
|
Scott W. Smith, our former President and Chief Executive Officer.
|
Name and Principal Position
|
Year
|
Salary
(1)
|
Bonus
(2)
|
Stock
Awards (3) |
All Other Compensation
(4)
|
Total
|
||||||||||||
R. Scott Sloan, President & CEO
|
2018
|
$
|
691,353
|
|
$
|
127,500
|
|
|
$
|
3,126,149
|
|
|
$
|
8,231
|
|
$
|
3,953,233
|
|
|
2017
|
$
|
133,384
|
|
$
|
127,500
|
|
|
$
|
24,375
|
|
|
$
|
8,003
|
|
$
|
293,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Ryan Midgett, CFO
|
2018
|
$
|
296,587
|
|
$
|
166,526
|
|
|
$
|
1,302,572
|
|
|
$
|
16,500
|
|
$
|
1,782,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Jonathan C. Curth, General Counsel, Corporate Sectretary, Compliance Officer & VP of Land
|
2018
|
$
|
305,000
|
|
$
|
30,000
|
|
|
$
|
416,825
|
|
|
$
|
16,500
|
|
$
|
768,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Scott W. Smith,
|
2018
|
$
|
90,192
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,764,326
|
|
$
|
1,854,518
|
|
Former President & CEO
|
2017
|
$
|
650,000
|
|
$
|
717,969
|
|
|
$
|
3,575,000
|
|
|
$
|
553,565
|
|
$
|
5,496,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Britt Pence,
|
2018
|
$
|
230,000
|
|
$
|
91,406
|
|
|
$
|
—
|
|
|
$
|
1,419,366
|
|
$
|
1,740,772
|
|
Former EVP of Operations
|
2017
|
$
|
450,000
|
|
$
|
595,000
|
|
|
$
|
1,575,000
|
|
|
$
|
230,979
|
|
$
|
2,850,979
|
|
(1)
|
Fiscal year 2018 salary presented for Mr. Smith reflects his salary for his service as President and CEO from January 1, 2018 to January 17, 2018 and his salary for his services in his non-executive position through February 16, 2019. Fiscal year 2018 salary presented for Mr. Pence reflects his salary for his service as Executive Vice President of Operations from January 1, 2018 to June 29, 2018. Fiscal year 2017 salary presented for Mr. Sloan reflects his service as Chief Financial Officer from September 26, 2017 to December 31, 2017 and also includes $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 and Pence, the 2017 bonus represents amounts accrued under their employment agreements that were in effect prior to the Effective Date. Such amounts include a quarterly bonus accrued with respect to the fiscal quarters ended December 31, 2016, March 31, 2017 and June 30, 2017, but that were not payable until after the Effective Date. With respect to Mr. Pence, the 2018 bonus represents a pro-rated bonus for his service in 2018.
|
(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. On January 17, 2018, Messrs. Sloan, Midgett, and Curth received 38,462, 16,026, and 5,128 Initial Time RSUs (as discussed below in “Narrative Disclosure to Summary Compensation Table”
)
, respectively, valued at $19.50 per share. Each restricted stock unit (“RSU”) represents the right to receive one share of Common Stock. On September 11, 2018, Messrs. Sloan, Midgett, and Curth received awards of 76,922, 32,051, and 10,257 Cliff RSUs respectively, valued at $21.01 per share. Additionally, on September 11, 2018, Messrs. Sloan, Midgett and Curth received awards of 38,462, 16,026, and 5,128 PSUs, respectively, valued at $19.76 per share (assuming target achievement of the performance objectives based upon the then-probable outcome of the applicable performance goals on the grant date). The maximum value of each of Messrs. Sloan, Midgett, and Curth’s PSU awards is $1,520,018, $633,348, and $202,659, respectively, assuming maximum achievement of the applicable performance goals. The equity awards granted to Messrs. Smith and Pence in 2017 were phantom unit awards granted on January 1, 2017 with respect to the 2016 performance year and the Predecessor’s equity. In connection with the implementation of the Final 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. Please read Note 12 of the Notes to the Consolidated Financial Statements included in Part II, Item 8 of this Annual Report, for further discussion on the assumptions made in the valuation.
|
(4)
|
Amount shown for Messrs. Sloan, Midgett and Curth in 2018 and 2017 is the amount received in the form of matching contributions to our 401(k) Plan. With respect to Mr. Smith the 2018 other compensation amount is attributable to $1,750,000 in severance pay, $8,410 in accrued vacation and $5,916 in matching 401(k) contributions. With respect to Mr. Pence the 2018 other compensation amount is attributable to $1,400,000 in severance pay, $2,866 in accrued vacation and $16,500 in matching 401(k) contributions. 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.
|
Name
|
Number of shares or units of stock that have not vested
(2)
|
Market value of shares or units of stock that have not vested
|
Equity incentive plan awards: number of unearned shares, units or other rights that have not vested
(3)
|
Equity incentive plan awards: market or payout value of unearned shares, units or other rights that have not vested
|
||||||
R. Scott Sloan
|
102,563
|
|
$
|
148,716
|
|
38,462
|
|
$
|
55,770
|
|
Ryan Midgett
|
42,735
|
|
$
|
61,966
|
|
16,026
|
|
$
|
23,238
|
|
Jonathan C. Curth
|
13,675
|
|
$
|
19,829
|
|
5,128
|
|
$
|
7,436
|
|
Scott W. Smith
(1)
|
—
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
Britt Pence
(1)
|
—
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
Name
(1)
|
Fees Earned or Paid in Cash ($)
|
|
Stock Awards ($)
(8)(9)
|
Total ($)
|
||||||
Joseph Citarrella
(2)
|
$
|
125,000
|
|
|
$
|
—
|
|
$
|
125,000
|
|
Randall Albert
(3)
|
$
|
101,667
|
|
|
$
|
80,834
|
|
$
|
180,834
|
|
Michael Alexander
(4)
|
$
|
125,000
|
|
|
$
|
—
|
|
$
|
125,000
|
|
W. Greg Dunlevy
(5)
|
$
|
125,000
|
|
|
$
|
75,428
|
|
$
|
200,428
|
|
Joseph Hurliman Jr.
(6)
|
$
|
85,833
|
|
|
$
|
113,391
|
|
$
|
199,224
|
|
Graham Morris
(7)
|
$
|
125,000
|
|
|
$
|
—
|
|
$
|
125,000
|
|
(1)
|
Mr. Sloan is not included in this table as he is also an executive officer and received no additional compensation for his service as director. All compensation provided to or earned by Mr. Sloan for 2018 is reported in the Summary Compensation Table above.
|
(2)
|
Mr. Citarrella resigned from the board on December 19, 2018. He was not personally compensated for his services on the Board; rather, his compensation was passed to Monarch, his employer, if and as applicable to his role on the Board. In 2018, Monarch received approximately $125,000 in connection with Mr. Citarrella’s service as a director.
|
(3)
|
Mr. Albert received $101,667 for his service as a non-management director, including a pro-rated fee for his service as Chairman of the Compensation Committee, during the fiscal year ended December 31, 2018. He also received 14,832 RSUs, with a grand date value of $5.45 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. The RSUs vest ratably on the first three anniversaries of September 11, 2018. Settlement of RSUs will be at the earliest of: (i) Mr. Albert’s termination of service or (ii) a change in control event.
|
(4)
|
Mr. Alexander resigned from the board on February 1, 2019. He was not personally compensated for his services on the Board; rather, his compensation was passed to Marathon, his employer, if and as applicable to his role on the Board. In 2018, Marathon received approximately $125,000 in connection with Mr. Alexander’s service as a director and as Chairman of the Nominating & Governance Committee.
|
(5)
|
Mr. Dunlevy received $125,000 for his service as a non-management director and as the Chairman of the Audit Committee during the fiscal year ended December 31, 2018. He also received 13,840 RSUs, with a grant date value of $5.45 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. The RSUs vest ratably on the first three anniversaries of September 11, 2018. Settlement of RSUs will be at the earliest of: (i) Mr. Dunlevy’s termination of service or (ii) a change in control event.
|
(6)
|
Mr. Hurliman received $85,833 for his service as a non-management director during the fiscal year ended December 31, 2018. He also received 4,419 RSUs, with a grant date value of $11.99 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, March 20, 2018. The remaining RSUs vest ratably on the first three anniversaries of the Grant Date.
Additionally, on September 11, 2018, he received 7,841 RSUs, with a grant date value of $5.45 per share, pursuant to the MIP. The RSUs vest ratably on the first three anniversaries of the Grant Date. Settlement of RSUs will be at the earliest of: (i) Mr. Hurliman’s termination of service or (ii) a change in control event.
|
(7)
|
Mr. Morris resigned from the board on February 1, 2019. He was not personally compensated for his services on the Board; rather, his compensation was passed to Contrarian, his employer, if and as applicable to his role in the determination of the Board. In 2018, Contrarian received approximately $125,000 in connection with Mr. Morris’s service as a director.
|
(8)
|
As of December 31, 2018, each non-employee director held the following outstanding stock awards:
|
Director
|
Stock Awards Outstanding
|
Market value of shares that have not vested
|
||
Joseph Citarrella
|
—
|
$
|
—
|
|
Randall Albert
|
17,332
|
$
|
25,131
|
|
Michael Alexander
|
—
|
$
|
—
|
|
W. Greg Dunlevy
|
16,340
|
$
|
23,693
|
|
Joseph Hurliman Jr.
|
12,260
|
$
|
17,777
|
|
Graham Morris
|
—
|
$
|
—
|
|
(9)
|
Please read Note 12 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, for further discussion on the assumptions made in the valuation of stock awards.
|
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:
|
|
344,819
|
|
(1)
|
$
|
—
|
|
|
|
1,888,514
|
|
(2)
|
(1)
|
This amount includes 53,656 deferred restricted stock units and 291,163 non-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 2017 Bankruptcy Court in connection with the Plan.
|
Name of Beneficial Owner
|
Shares
|
Percent of Class
|
|||
|
|
|
|
||
5% Owners
|
|
|
|
||
Marathon Asset Management, L.P.
(1)
|
4,890,043
|
|
24.3
|
|
%
|
Contrarian Capital Management, L.L.C.
(2)
|
3,351,073
|
|
16.7
|
|
%
|
Monarch Alternative Capital LP
(3)
|
2,045,773
|
|
10.2
|
|
%
|
Silver Point Capital, L.P.
(4)
|
1,415,116
|
|
7.0
|
|
%
|
FMR LLC
(5)
|
1,209,218
|
|
6.0
|
|
%
|
|
|
|
|
||
Directors
|
|
|
|
||
Randall M. Albert
|
2,500
(6)
|
|
*
|
|
|
Patrick J. Bartels, Jr.
|
—
|
|
—
|
|
|
W. Greg Dunlevy
|
2,500
(7)
|
|
*
|
|
|
Joseph Hurliman Jr.
|
1,474
(8)
|
|
—
|
|
|
Andrew E. Shultz
|
—
|
|
—
|
|
|
L. Spencer Wells
|
—
|
|
—
|
|
|
|
|
|
|
||
Named Executive Officers
|
|
|
|
||
R. Scott Sloan
|
14,071
(9)
|
|
*
|
|
|
Ryan Midgett
|
5,342
(10)
|
|
*
|
|
|
Britt Pence
|
—
|
|
—
|
|
|
Jonathan C. Curth
|
1,710
(11)
|
|
*
|
|
|
Scott W. Smith
|
—
|
|
—
|
|
|
|
|
|
|
||
All directors and executive officers as a group (11 persons)
|
27,597
|
|
*
|
|
%
|
(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. 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
April 8, 2019
. The business address of these funds and accounts is One Bryant Park, 38th Floor, New York, NY 10036.
|
(2)
|
This information is based solely on the Schedule 13G filed by Contrarian Capital Management, L.L.C on February 14, 2019. 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 pecuniary interests therein. The business address of TCAB is 411 West Putnam Ave, Ste 425, Greenwich, CT 06830.
|
(3)
|
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. The business address for each of the Monarch Funds is c/o Monarch Alternative Capital LP, 535 Madison Avenue, New York, NY 10022.
|
(4)
|
Based solely on a Schedule 13G filed with the SEC on February 14, 2019 by Silver Point Capital, L.P. Such filing indicates that Silver Point Capital, L.P. has shared voting and dispositive power with respect to 1,415,116 shares of our Common Stock. The address for Silver Point Capital, L.P. is Two Greenwich Plaza, Greenwich, CT 06830.
|
(5)
|
This information is based solely on the Schedule 13G filed by FMR LLC on February 13, 2018. Reflects accounts managed by direct or indirect subsidiaries of FMR LLC. Abigail P. Johnson is a Director, the Chairman and the Chief Executive Officer 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. FMR Co 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 V: Strategic Income Portfolio, Fidelity School Street Trust: Fidelity Strategic Income Fund and Fidelity Advisor Series II: Fidelity Advisor Strategic Income Fund is 245 Summer Street, Boston, MA 02210.
|
(6)
|
Comprises 2,500 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, upon any departure from the Board.
|
(7)
|
Comprises 2,500 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, upon any departure from the Board.
|
(8)
|
Comprises 1,474 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, upon any departure from the Board.
|
(9)
|
Comprises 14,071 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, upon any departure from the Board.
|
(10)
|
Comprises 5,342 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, upon any departure from the Board.
|
(11)
|
Comprises 1,710 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of
April 8, 2019
, 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,
|
|
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*
|
|
|
10.15**
|
|
|
10.16*
|
|
|
10.17*
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20
|
|
|
10.21*
|
|
|
10.22*
|
|
10.23
|
|
|
21.1**
|
|
|
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
|
**
|
Filed herewith.
|
***
|
Furnised herewith.
|
VANGUARD NATURAL RESOURCES, INC.
|
|||||
|
|
/s/ R. Scott Sloan
|
|||
|
R. Scott Sloan
|
||||
|
President and Chief Executive Officer
|
April 15, 2019
|
/s/ R. Scott Sloan
|
|
R. Scott Sloan
|
|
President, Chief Executive Officer and Director
|
|
(Principal Executive Officer)
|
|
|
April 15, 2019
|
/s/ Ryan Midgett
|
|
Ryan Midgett
|
|
Chief Financial Officer
|
|
(Principal Financial Officer)
|
|
|
April 15, 2019
|
/s/ Patty Avila-Eady
|
|
Patty Avila-Eady
|
|
Chief Accounting Officer
|
|
(Principal Accounting Officer)
|
|
|
April 15, 2019
|
/s/ Randall M. Albert
|
|
Randall M. Albert
|
|
Director
|
|
|
April 15, 2019
|
/s/ Patrick J. Bartels, Jr.
|
|
Patrick J. Bartels, Jr.
|
|
Director
|
|
|
April 15, 2019
|
/s/ W. Greg Dunlevy
|
|
W. Greg Dunlevy
|
|
Chairman of the Board of Directors
|
|
|
April 15, 2019
|
/s/ Joseph Hurliman Jr.
|
|
Joseph Hurliman Jr.
|
|
Director
|
|
|
April 15, 2019
|
/s/ Andrew W. Schultz
|
|
Andrew W. Schultz
|
|
Director
|
|
|
April 15, 2019
|
/s/ L. Spencer Wells
|
|
L. Spencer Wells
|
|
Director
|
1.
Payable if Quarterly Threshold Performance Metric Achieved:
|
50% of the Applicable Portion of the Participant’s Target Bonus
|
2.
Payable if Quarterly Target Performance Metric Achieved:
|
100% of the Applicable Portion of the Participant’s Target Bonus
|
3.
Payable if Quarterly Maximum Performance Metric Achieved:
|
200% of the Applicable Portion of the Participant’s Target Bonus
|
4.
Payable if Cumulative Quarterly Threshold Performance Metric Achieved:*
|
50% of the Applicable Portion of the Participant’s aggregate Target Bonus through the end of the Applicable Performance Period
|
5.
Payable if Cumulative Quarterly Target Performance Metric Achieved:*
|
100% of the Applicable Portion of the Participant’s aggregate Target Bonus through the end of the Applicable Performance Period
|
6.
Payable if Cumulative Quarterly Maximum Performance Metric Achieved:*
|
200% of the Applicable Portion of the Participant’s aggregate Target Bonus through the end of the Applicable Performance Period
|
7.
Portion of Applicable Portion Payable if Achievement is Between Performance Metrics:
|
Calculated on the basis of straight-line interpolation
|
8.
Overall Payment Cap
|
Bonus payments will be capped as follows: In no event shall a Participant’s total Bonus for a Quarter that is based on achieving a Quarterly Performance Metric exceed 150% of a Participant’s Target Bonus for that Quarter (“
Limit 1
”) and in no event shall a Participant’s Bonus for a Quarter that is based on achieving a Cumulative Performance Metric exceed 150% of the Participant’s aggregate Target Bonus through the end of such Quarter (“
Limit 2
” and, along with Limit 1, the “
Limits
”). Notwithstanding the foregoing, a Bonus payment shall be made to the extent it satisfies either Limit 1 or Limit 2. If Limit 1 or Limit 2 is exceeded, the amounts allocated to each performance metric shall be reduced on a pro rata basis for purposes of determining the amounts payable in subsequent Quarters. The Limits will be applied solely to the Bonuses paid under Section 6(a)-(d) and will not take into account any Supplemental Bonus.
|
*
|
As set forth in Section 6(b), payments for achieving Cumulative Performance Metrics reduced by amounts paid or payable for current and previous Quarters.
|
(i)
|
Performance Metric: Operated Production (mmscfe)
|
Performance Period:
|
First Performance Period
|
Second Performance Period
|
Third Performance Period
|
Fourth Performance Period
|
Quarterly Threshold Performance Goal
|
13,644
|
13,478
|
13,303
|
12,963
|
Quarterly Target Performance Goal
|
14,830
|
14,650
|
14,460
|
14,090
|
Quarterly Maximum Performance Goal
|
16,016
|
15,822
|
15,617
|
15,217
|
|
|
|
|
|
Cumulative Threshold Performance Goal
|
N/A
|
27,122
|
40,425
|
53,388
|
Cumulative Target Performance Goal
|
N/A
|
29,480
|
43,940
|
58,030
|
Cumulative Maximum Performance Goal
|
N/A
|
31,838
|
47,455
|
62,672
|
(ii)
|
Performance Metric: Operated LOE ($/mscfe)
|
Performance Period:
|
First Performance Period
|
Second Performance Period
|
Third Performance Period
|
Fourth Performance Period
|
Quarterly Threshold Performance Goal
|
1.41
|
1.51
|
1.43
|
1.39
|
Quarterly Target Performance Goal
|
1.27
|
1.36
|
1.29
|
1.25
|
Quarterly Maximum Performance Goal
|
1.13
|
1.21
|
1.15
|
1.11
|
|
|
|
|
|
Cumulative Threshold Performance Goal
|
N/A
|
1.46
|
1.45
|
1.44
|
Cumulative Target Performance Goal
|
N/A
|
1.31
|
1.31
|
1.29
|
Cumulative Maximum Performance Goal
|
N/A
|
1.17
|
1.16
|
1.15
|
(iii)
|
Performance Metric: Cash G&A ($ thousands)
|
Performance Period:
|
First Performance Period
|
Second Performance Period
|
Third Performance Period
|
Fourth Performance Period
|
Quarterly Threshold Performance Goal
|
12,460
|
11,890
|
11,582
|
11,799
|
Quarterly Target Performance Goal
|
10,930
|
10,430
|
10,160
|
10,350
|
Quarterly Maximum Performance Goal
|
9,400
|
8,970
|
8,738
|
8,901
|
|
|
|
|
|
Cumulative Threshold Performance Goal
|
N/A
|
24,350
|
35,933
|
47,732
|
Cumulative Target Performance Goal
|
N/A
|
21,360
|
31,520
|
41,870
|
Cumulative Maximum Performance Goal
|
N/A
|
18,370
|
27,107
|
36,008
|
(iv)
|
Performance Metric: Carnite Cash Flow Improvements ($ thousands)
|
Performance Period:
|
First Performance Period
|
Second Performance Period
|
Third Performance Period
|
Fourth Performance Period
|
Quarterly Threshold Performance Goal
|
0
|
1,840
|
2,040
|
2,300
|
Quarterly Target Performance Goal
|
0
|
2,300
|
2,550
|
2,875
|
Quarterly Maximum Performance Goal
|
0
|
2,760
|
3,060
|
3,450
|
|
|
|
|
|
Cumulative Threshold Performance Goal
|
N/A
|
1,840
|
3,880
|
6,180
|
Cumulative Target Performance Goal
|
N/A
|
2,300
|
4,850
|
7,725
|
Cumulative Maximum Performance Goal
|
N/A
|
2,760
|
5,820
|
9,270
|
By:
|
Vanguard Natural Gas, LLC, Its Sole Member
|
Date
|
Assignor
|
Assignee
|
Facility Assigned
|
Amount of Revolving Credit Commitment/Loan Assignment
|
|
12/12/17
|
SUNTRUST
BANK |
Citibank, N.A.
|
Term Loan
|
$1,315,130.26
|
|
1/26/18
|
ZB, N.A.
|
Barclays Bank PLC
|
Term Loan
|
$1,499,248.49
|
|
1/31/2018
|
Barclays Bank
PLC |
Cross Sound Distressed Opportunities Fund, L.P. - Series 3
|
Term Loan
|
$1,123,135.42
|
|
3/14/2018
|
The Bank of Nova Scotia
|
Barclays Bank PLC
|
Term Loan
|
$3,420,160.63
|
|
3/15/2018
|
Knighthead (NY) Fund, L.P.
|
Barclays Bank PLC
|
Revolving Credit
Commitment
|
$3,206,599.16
|
|
3/15/2018
|
Knighthead Annuity & Life Assurance Company
|
Barclays Bank PLC
|
Revolving Credit
Commitment
|
$3,799,544.55
|
|
3/15/2018
|
KNIGHTHEAD MASTER FUND, L.P.
|
Barclays Bank PLC
|
Revolving Credit
Commitment
|
$27,720,946.51
|
|
3/16/2018
|
Barclays Bank
PLC |
Cross Sound Distressed Opportunities Fund, L.P. - Series 3
|
Revolving Credit
Commitment
|
$4,852,941.18
|
|
3/16/2018
|
Barclays Bank
PLC |
Cross Sound Distressed Opportunities Fund, L.P. - Series 3
|
Revolving Credit
Commitment
|
$9,908,362.66
|
|
3/16/2018
|
Barclays Bank
PLC |
Cross Sound Distressed Opportunities Fund, L.P. - Series 3
|
Revolving Credit
Commitment
|
$19,411,764.71
|
|
4/13/2018
|
ZB, N.A.
|
Barclays Bank PLC
|
Revolving Credit
Commitment
|
$13,226,452.91
|
|
4/16/2018
|
The Bank of Nova Scotia
|
Barclays Bank PLC
|
Revolving Credit
Commitment
|
$10,000,000.00
|
|
5/3/2018
|
UBS AG,
Stamford Branch
|
WHITEBOX CAJA BLANCA FUND LP
|
Term Loan
|
$3,411,588.80
|
|
5/7/2018
|
Citibank, N.A.
|
WHITEBOX ASYMMETRIC PARTNERS LP
|
Term Loan
|
$645,478.20
|
|
5/7/2018
|
Citibank, N.A.
|
WHITEBOX MULTI STRATEGY PARTNERS LP
|
Term Loan
|
$663,076.41
|
|
8/20/2018
|
Citibank, N.A.
|
CITI TROUBLED DEBT
RESTRUCTURE
|
Term Loan
|
$3,636,100.32
|
|
8/20/2018
|
Citibank, N.A.
|
CITI TROUBLED DEBT
RESTRUCTURE
|
Revolving Credit
Commitment
|
$27,462,565.24
|
|
9/24/2018
|
KNIGHTHEAD NY FUND LP
|
HSBC BANK PLC
|
Term Loan
|
$361,653.37
|
|
9/24/2018
|
KNIGHTHEAD ANNUITY AND LIFE
|
HSBC BANK PLC
|
Term Loan
|
$428,528.18
|
|
9/24/2018
|
KNIGHTHEAD MASTER FUND, L.P.
|
HSBC BANK PLC
|
Term Loan
|
$3,126,481.75
|
|
11/7/2018
|
DEUTSCHE BANK AG NEW YORK BRANCH
|
BANK OF MONTREAL
|
Term Loan
|
$3,394,445.14
|
|
11/29/2018
|
DEUTSCHE BANK AG NEW YORK BRANCH
|
BANK OF MONTREAL
|
Revolving Credit
Commitment
|
$25,199,263.53
|
|
12/5/2018
|
The Bank of Nova Scotia
|
Black Diamond Credit Strategies Master Fund, Ltd.
|
Revolving Credit
Commitment
|
$4,901,001.05
|
|
Name of Lender
|
Commitment
|
Applicable Percentage
|
BANK OF MONTREAL
|
$49,583,509.12
|
7.315%
|
BARCLAYS BANK PLC(NEW YORK BRANCH)
|
$44,331,167.41
|
6.540%
|
BLACK DIAMOND CREDIT STRATEGIES
MASTER FUND LTD (FKA) BDC FINANCE LTD |
$14,541,155.07
|
2.145%
|
WELLS FARGO BANK NA
|
$30,225,563.77
|
4.459%
|
CROSS SOUND DISTRESSED OPPORTUNITIES
FUND LP SERIES 3 (FKA) CROSS SOUND ENERGY OPPORTUNITY FUND LP SERIES 3 |
$28,078,568.94
|
4.142%
|
CITIBANK, N.A. - ORIGINATIONS
|
$26,489,820.04
|
3.908%
|
ABN AMRO CAPITAL USA LLC
|
$24,791,754.56
|
3.657%
|
BANK OF AMERICA NA
|
$24,791,754.56
|
3.657%
|
CIBC INC
|
$24,791,754.56
|
3.657%
|
CITIZENS BANK
|
$24,791,754.56
|
3.657%
|
CREDIT AGRICOLE
|
$24,791,754.56
|
3.657%
|
FIFTH THIRD BANK (FIFTH THIRD)
|
$24,791,754.56
|
3.657%
|
ING CAPITAL LLC
|
$24,791,754.56
|
3.657%
|
JPMORGAN CHASE BANK NA (JPM CHASE)
|
$24,791,754.56
|
3.657%
|
NATIXIS NEW YORK BRANCH
|
$24,791,754.56
|
3.657%
|
PNC BANK, N.A.
|
$24,791,754.56
|
3.657%
|
ROYAL BANK OF CANADA
|
$24,791,754.56
|
3.657%
|
SUMITOMO MITSUI BANKING CORP.
|
$24,791,754.56
|
3.657%
|
U.S. BANK NATIONAL ASSOCIATION
|
$24,791,754.56
|
3.657%
|
UBS AG, STAMFORD BRANCH
|
$24,791,754.56
|
3.657%
|
CAPITAL ONE, N.A. CAPITAL ONE
FINANCIAL CORPORATION (PARENT) |
$18,678,719.19
|
2.756%
|
COMERICA BANK
|
$18,678,719.19
|
2.756%
|
COMMONWEALTH BANK OF AUSTRALIA
NEW YORK BRANCH |
$18,678,719.19
|
2.756%
|
ASSOCIATED BANK NA
|
$14,603,362.27
|
2.154%
|
BANC OF AMERICA CREDIT PRODUCTS INC
|
$20,518,236.30
|
3.027%
|
WHITNEY BANK
|
$12,226,070.74
|
1.804%
|
HUNTINGTON NATIONAL BANK
(HUNTINGTON) |
$9,509,166.13
|
1.403%
|
SUNTRUST BANK
|
$9,509,166.13
|
1.403%
|
CHASE LINCOLN FIRST COMMERCIAL
CORPORATION |
$3,396,130.76
|
0.501%
|
BANK OF NOVA SCOTIA
|
$11,735,061.99
|
1.731%
|
Total
|
$677,867,700.00
|
100.000%
|
Name of Lender
|
Commitment
|
Applicable
Percentage |
BARCLAYS BANK PLC(NEW YORK BRANCH)
|
$7,144,089.12
|
5.788%
|
BANK OF MONTREAL
|
$6,771,746.62
|
5.486%
|
BANC OF AMERICA CREDIT PRODUCTS INC
|
$6,670,893.80
|
5.404%
|
JPMORGAN CHASE BANK NA (JPM CHASE)
|
$5,711,339.92
|
4.627%
|
CONTRARIAN FUNDS, LLC
|
$5,428,194.29
|
4.398%
|
MORGAN STANLEY SENIOR FUNDING INC
SENIOR FUNDING INC |
$4,890,167.28
|
3.962%
|
WELLS FARGO BANK NA
|
$4,127,982.53
|
3.344%
|
HSBC BANK PLC (HSBC)
|
$3,896,932.00
|
3.157%
|
CITI TROUBLED DEBT RESTRUCTURE CBNA
|
$3,617,782.43
|
2.931%
|
MONARCH MASTER FUNDING LTD
|
$3,565,885.34
|
2.889%
|
MARATHON SPECIAL OPPORTUNITY MASTER
FUND LTD |
$3,403,789.99
|
2.758%
|
BANK OF AMERICA NA
|
$3,385,873.31
|
2.743%
|
WHITEBOX CAJA BLANCA FUND LP
|
$3,385,873.31
|
2.743%
|
ABN AMRO CAPITAL USA LLC
|
$3,385,873.30
|
2.743%
|
CIBC INC
|
$3,385,873.30
|
2.743%
|
CITIZENS BANK
|
$3,385,873.30
|
2.743%
|
CREDIT AGRICOLE CIB-NEW YORK-NY BRANCH
|
$3,385,873.30
|
2.743%
|
FIFTH THIRD BANK (FIFTH THIRD)
|
$3,385,873.30
|
2.743%
|
ING CAPITAL LLC
|
$3,385,873.30
|
2.743%
|
NATIXIS NEW YORK BRANCH
|
$3,385,873.30
|
2.743%
|
PNC BANK, N.A.
|
$3,385,873.30
|
2.743%
|
ROYAL BANK OF CANADA
|
$3,385,873.30
|
2.743%
|
SUMITOMO MITSUI BANKING CORP. (FKA THE
SUMITOMO BANK) |
$3,385,873.30
|
2.743%
|
U.S. BANK NATIONAL ASSOCIATION
|
$3,385,873.30
|
2.743%
|
CAPITAL ONE, N.A. CAPITAL ONE FINANCIAL
CORPORATION (PARENT) |
$2,551,000.44
|
2.067%
|
COMERICA BANK
|
$2,551,000.44
|
2.067%
|
COMMONWEALTH BANK OF AUSTRALIA NEW
YORK BRANCH |
$2,551,000.44
|
2.067%
|
CROSS SOUND DISTRESSED OPPORTUNITIES
FUND LP SERIES 3 (FKA) CROSS SOUND ENERGY OPPORTUNITY FUND LP SERIES 3 |
$2,003,347.41
|
1.623%
|
ASSOCIATED BANK NA
|
$1,994,418.53
|
1.616%
|
MARATHON CENTRE STREET PARTNERSHIP LP
|
$1,874,636.98
|
1.519%
|
HANCOCK WHITNEY BANK (FKA) WHITNEY
BANK
|
$1,669,745.74
|
1.353%
|
BLACK DIAMOND CREDIT STRATEGIES MASTER
FUND LTD (FKA) BDC FINANCE LTD |
$1,324,895.94
|
1.073%
|
HUNTINGTON NATIONAL BANK (HUNTINGTON)
|
$1,298,691.13
|
1.052%
|
WHITEBOX MULTI STRATEGY PARTNERS LP
(WHITEBOX ADVISORS LLC) |
$1,130,812.80
|
0.916%
|
WHITEBOX ASYMMETRIC PARTNERS LP
|
$950,335.37
|
0.770%
|
TRS CREDIT FUND LP (FKA) KTRS CREDIT FUND
LP
|
$759,227.96
|
0.615%
|
MARATHON CREDIT DISLOCATION FUND, LP
(MARATHON ASSET MANAGEMENT, L.P) |
$637,478.46
|
0.516%
|
MARATHON BLUE GRASS CREDIT FUND LP
|
$622,705.46
|
0.504%
|
MASTER SIF SICAV SIF
|
$583,175.23
|
0.472%
|
CHASE LINCOLN FIRST COMMERCIAL
CORPORATION |
$463,818.26
|
0.376%
|
ARISTEIA MASTER LP
|
$325,921.91
|
0.264%
|
REEF ROAD MASTER FUND LTD
|
$299,942.02
|
0.243%
|
SIERRA PACIFIC SECURITIES LLC
|
$181,147.00
|
0.147%
|
PENTELI MASTER FUND LTD (MARATHON ASSET MANAGEMENT)
|
$108,708.63
|
0.088%
|
FIRST BALLANTYNE LLC
|
$97,399.28
|
0.079%
|
JAMES MICHAEL FORD
|
$50,941.12
|
0.041%
|
THREE LITTLE BIRDS INVESTMENTS LLC
|
$50,941.12
|
0.041%
|
WHITEBOX INSTITUTIONAL PARTNERS LP
|
$32,602.31
|
0.026%
|
CITIBANK NA
|
$27,915.69
|
0.023%
|
WINDERMERE IRELAND FUND PLC
|
$18,950.13
|
0.015%
|
CLARENCE HUGS EDWARDS JR
|
$15,282.48
|
0.012%
|
FRED C ALEXANDER III
|
$5,094.27
|
0.004%
|
SCOTT J SIMONS
|
$5,094.27
|
0.004%
|
JOHN EDWARD KRESHON
|
$4,075.29
|
0.003%
|
MICHAEL D JOHNSON
|
$2,037.65
|
0.002%
|
Total:
|
$123,437,500.00
|
100.00%
|
|
|
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, Inc.
|
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.
|
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.
|
Date: April 15, 2019
|
/s/ Ryan Midgett
|
|
Ryan Midgett
|
|
|
|
Chief Financial Officer
|
|
(Principal Financial Officer)
|
|
Vanguard Natural Resources, Inc.
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ R. Scott Sloan
|
|
R. Scott Sloan
|
|
|
|
President and Chief Executive Officer
|
|
(Principal Executive Officer)
|
|
|
|
April 15, 2019
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Ryan Midgett
|
|
Ryan Midgett
|
|
|
|
Chief Financial Officer
|
|
(Principal Financial Officer)
|
|
|
|
April 15, 2019
|