Commission File Number 001-33756

 

Vanguard Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		80-0411494
(State or Other Jurisdiction of  Incorporation or Organization)		(I.R.S. Employer  Identification No.)
5847  San Felipe, Suite 3000  Houston, Texas		77057
(Address of Principal Executive Offices)		(Zip Code)

Large accelerated filer o		Accelerated filer o
Non-accelerated filer x		Smaller reporting company x
		Emerging growth company o

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•	our ability to continue as a going concern;

•	our ability to meet our liquidity needs and service our indebtedness;

•	our ability to access the public capital markets;

•	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;

•	inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our 2019 Bankruptcy Petitions (as defined herein);

•	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;

•	our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•	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);

•	Bankruptcy Court rulings in the 2019 Chapter 11 Cases and the outcome of the 2019 Chapter 11 Cases in general;

•	the outcome of all other pending litigation;

•	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;

•	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;

•	the potential adverse effects of the 2019 Chapter 11 Cases on our liquidity and results of operations;

•	increased advisory costs to execute a reorganization;

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•	risks relating to any of our unforeseen liabilities;

•	declines in oil, NGLs or natural gas prices;

•	the level of success in exploration, development and production activities;

•	adverse weather conditions that may negatively impact development or production activities;

•	the timing of exploitation and development expenditures;

•	inaccuracies of reserve estimates or assumptions underlying them;

•	revisions to reserve estimates as a result of changes in oil, natural gas and NGLs prices;

•	impacts to financial statements as a result of impairment write-downs;

•	risks related to the level of indebtedness and periodic redeterminations of the borrowing base under our credit agreements;

•	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;

•	ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget;

•	ability to obtain external capital to finance exploration and development operations and acquisitions;

•	compliance with applicable laws, rules and regulations;

•	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;

•	federal, state and local initiatives and efforts relating to the regulation of development drilling and hydraulic fracturing;

•	failure of properties to yield oil or natural gas in commercially viable quantities;

•	uninsured or underinsured losses resulting from oil and natural gas operations;

•	ability to access oil and natural gas markets due to market conditions or operational impediments;

•	the impact and costs of compliance with laws and regulations governing oil and natural gas operations;

•	ability to replace oil and natural gas reserves;

•	any loss of senior management or technical personnel;

•	competition in the oil and natural gas industry;

•	risks arising out of hedging transactions;

•	the costs and effects of litigation;

•	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

•	costs of tax treatment as a corporation.

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GLOSSARY OF TERMS

 

Below is a list of terms that are common to our industry and used throughout this document:

/day	= per day		Mcf	= thousand cubic feet
Bbls	= barrels		Mcfe	= thousand cubic feet of natural gas equivalents
Bcf	= billion cubic feet		MMBbls	= million barrels
Bcfe	= billion cubic feet equivalents		MMBOE	= million barrels of oil equivalent
BOE	= barrel of oil equivalent		MMBtu	= million British thermal units
Btu	= British thermal unit		MMcf	= million cubic feet
MBbls	= thousand barrels		MMcfe	= million cubic feet of natural gas equivalents
MBOE	= thousand barrels of oil equivalent		NGLs	= natural gas liquids

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PART I

 

ITEM 1.  BUSINESS

 

Overview

We are an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States. Through our operating subsidiaries, as of December 31, 2018 , we own properties and oil and natural gas reserves primarily located in nine operating basins:

•	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.

The Predecessor was formed in October 2006 as a Delaware limited liability company named Vanguard Natural Resources, LLC and completed its initial public offering in October 2007. On August 1, 2017, we emerged from bankruptcy and reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. Please read “Emergence from Voluntary Reorganization under Chapter 11 Proceedings” included under Part I, Item 1 of this Annual Report for additional information.

Following the completion of the financial restructuring on August 1, 2017 (Notes 2, 14 and 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report), the Company had 20.1 million shares of its common stock outstanding. The Company’s shares of common stock and two series of warrants are traded and quoted on the OTC Pink marketplace (the “OTC Pink”), which is operated by OTC Markets Group, Inc., under the symbols VNRRQ, VNRVQ and VNRWQ, respectively.

On April 1, 2019, we received notice from the OTC Markets Group Inc. notifying us that, effective April 2, 2019, it was removing the shares of our common stock, par value $0.001 (“Common Stock”), and two series of outstanding warrants from the OTCQX U.S. tier of the OTC Markets and downgrading them to the OTC Pink in light of the 2019 Bankruptcy Petitions. The OTC Pink is a more limited market than the OTCQX U.S. tier, and the quotation of our Common Stock on the OTC Pink may result in a less liquid market available for existing and potential stockholders to trade our Common Stock and could further depress the trading price of our Common Stock. There can be no assurance that any public market for our Common Stock will exist in the future or that the Company or its successor will be able to participate again in the OTCQX U.S. tier.

Recent Developments

Going Concern Assessment and Management’s Plans

As discussed further in Part I, Item 1A “Risk Factors”, Item 7 “Management’s Discussion & Analysis of Financial Condition and Results of Operations”, and Note 1 to our Financial Statements, we have concluded that there is substantial doubt about our ability to continue as a going concern, and the report of the independent registered public accounting firm that accompanies the audited consolidated financial statements for the year ended December 31, 2018 included in this Annual Report on Form 10-K contains an explanatory paragraph regarding substantial doubt about our ability to continue as a going concern due to the filing of the 2019 Chapter 11 Cases (as described under “Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Debt and Credit Facilities”).

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Bankruptcy Proceedings under Chapter 11

Commencement of Bankruptcy Cases

During the year ended December 31, 2018, the Company’s liquidity and ability to maintain compliance with debt covenants have been negatively impacted by borrowing base redeterminations under the Successor Credit Facility (as defined herein), lower-than-expected proceeds from asset divestitures, low realized commodity prices due to the Company's hedges and lower-than-expected economic returns from capital expenditures.

On March 31, 2019, the Company and certain subsidiaries (such subsidiaries, together with the Company, the “2019 Debtors”) filed voluntary petitions for relief (collectively, the “2019 Bankruptcy Petitions” and, the cases commenced thereby, the “2019 Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The 2019 Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the 2019 Chapter 11 Cases under the caption “In re: Vanguard Natural Resources, Inc., et al.”

The subsidiary Debtors in the 2019 Chapter 11 Cases are VNG, VNRH, VO, EOC, EAC, ERAC, ERUD, ERAP, ERAC II, ERUD II and ERAP II.

No trustee has been appointed and the Company continues to manage itself and its affiliates and operate their businesses as “debtors-in-possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The Company expects to continue its operations without interruption during the pendency of the 2019 Chapter 11 Cases. To assure ordinary course operations, the Debtors secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize the Debtors to maintain their existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees.

Debtor-in-Possession Financing

In connection with the 2019 Chapter 11 Cases, on March 31, 2019 (the “2019 Petition Date”), the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lender under the DIP Credit Agreement is Citibank N.A. The DIP Credit Agreement contains the following terms:

•	a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019;

•	a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under the Successor Credit Facility (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);

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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;

•

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

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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;

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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;

•	the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10.0 million, prepayment events, events of default and other provisions; and

•	generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date.

The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time and the Roll-Up is subject to the entry of the Final Dip Order by the Bankruptcy Court. We can provide no assurances that the DIP Motion will be granted.

Acceleration of Debt Obligations

The commencement of the 2019 Chapter 11 Cases described above is an event of default that accelerated the Debtors’ obligations under the following debt instruments (the “Debt Instruments”). Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code.

•	$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.

•	$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”).

Emergence from Voluntary Reorganization under 2017 Chapter 11 Proceedings

On February 1, 2017, the Predecessor and certain of its subsidiaries (the “2017 Debtors”) filed voluntary petitions (collectively, the “2017 Bankruptcy Petitions” and, the cases commenced thereby, the “2017 Chapter 11 Cases”) for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “2017 Bankruptcy Court”). The 2017 Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.” On July 18, 2017, the 2017 Bankruptcy Court entered the Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code, which approved and confirmed the 2017 Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Final Plan”). The Company emerged from bankruptcy effective August 1, 2017.

Upon emergence from bankruptcy, we made multiple changes to our accounting policies including the application of fresh-start accounting. Please read Critical Accounting Policies and Estimates included under Part II, Item 7 for a discussion of fresh-start accounting and other accounting policy changes.

Proved Reserves

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Our total estimated proved reserves at December 31, 2018 were 1,077.5 Bcfe, of which approximately 19% were oil reserves, 64% were natural gas reserves and 17% were NGLs reserves. Of these total estimated proved reserves, approximately  100%  were classified as proved developed.  As of December 31, 2018 , we have removed all proved undeveloped reserves from our total estimated proved reserves due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves. For information regarding such removal of our proved undeveloped reserves, please read “Oil, Natural Gas and NGLs Data - Proved Undeveloped Reserves .” At December 31, 2018 , estimated future cash inflows from estimated future production of proved reserves were computed in accordance with the U.S. Securities and Exchange Commission (“SEC”) rules using the average oil, natural gas and NGLs price based upon the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”) of $65.66 per barrel of crude oil, $3.10 per MMBtu for natural gas, and $26.57 per barrel of NGLs, as described under “Oil, Natural Gas and NGLs Data - Estimated Proved Reserves.”

At December 31, 2018 , we owned working interests in 10,330 gross ( 3,620 net) productive wells. Our operated wells accounted for approximately 60% of our total estimated proved reserves at December 31, 2018 . Our average net daily production was 346,128 Mcfe/day for the year ended December 31, 2018 and was 324,478 Mcfe/day for the fourth quarter of 2018 . Our average proved reserves-to-production ratio, or average reserve life, is approximately eight years based on our total proved reserves as of December 31, 2018 and our fourth quarter 2018 annualized production.

Oil and Natural Gas Properties

 

As of December 31, 2018 , through certain of our subsidiaries, we own interests in oil and natural gas properties located in nine operating basins. The following table presents the production for the year ended December 31, 2018 and the estimated proved developed reserves for each operating area:

		2018 Net Production
		Natural Gas			Oil			NGLs			Total			Net Estimated Proved Reserves			PV-10 Value (b)
		(MMcf)			(MBbls)			(MBbls)			(MMcfe)			(MMcfe)			(in millions)
Green River Basin		37,255			348			693			43,503			293,658			$	268.0
Piceance Basin		17,498			178			1,241			26,011			259,434			$	245.7
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”).

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(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.

The following is a description of our properties by operating basin:

Green River Basin Properties

Our Green River Basin properties are primarily comprised of assets in the Pinedale and Jonah fields of southwestern Wyoming. Production in these fields is dominated by natural gas and NGLs from tight sands formations. The Pinedale field lies at depths anywhere between 11,000 to 14,000 feet with similar depths in the adjacent Jonah field. As of December 31, 2018 , our Green River Basin properties consisted of 89,000 gross ( 14,132 net) leasehold acres. During 2018 , the Green River Basin properties produced approximately 43,503 MMcfe of which 86% was natural gas. At December 31, 2018 , the properties had total proved reserves of approximately 293,658 MMcfe or 27% of our total estimated proved reserves at year end, of which 100% were proved developed and 87% were natural gas. In March 2018, we completed the sale of certain oil and natural gas properties in the Green River Basin. Net cash proceeds received from the sale were approximately $4.5 million, net of transaction costs and subject to customary post-closing adjustments. The net cash proceeds were used to pay down outstanding debt under the Successor Credit Facility.

Piceance Basin Properties

The Piceance Basin is located in northwestern Colorado. Our Piceance Basin properties, which we operate, are located in the Gibson Gulch. The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 6,000 to 8,000 feet. As of December 31, 2018 , our Piceance Basin properties consisted of 25,320 gross ( 17,355 net) leasehold acres. During 2018 , our properties in the Piceance Basin produced approximately 26,011 MMcfe, of which 67% was natural gas. At December 31, 2018 , the Piceance Basin properties accounted for approximately 259,434 MMcfe or 24% of our total estimated proved reserves at year end, of which 100% were proved developed and 66% were natural gas.

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States extending over West Texas and southeast New Mexico. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. Our Permian Basin properties are located in several counties that extend from Eddy County, New Mexico to Val Verde County, Texas and encompass hundreds of fields with multiple producing intervals. The majority of our producing wells in the Permian Basin are mature oil wells that also produce high-Btu casinghead gas with significant NGLs content. These properties primarily produce at depths ranging from 2,000 feet to 12,000 feet. As of December 31, 2018 , our Permian Basin properties consisted of 335,118 gross ( 230,837 net) leasehold acres. During 2018 , our Permian Basin operations produced approximately 15,907 MMcfe, of which 62% was oil, condensate and NGLs. At December 31, 2018 , these properties accounted for approximately 148,985 MMcfe or 14% of our total estimated proved reserves at year end, of which 100% were proved developed and 65% were oil, condensate and NGLs.

Arkoma Basin Properties

Our Arkoma Basin properties include properties in the Woodford Shale located in eastern Oklahoma, as well as royalty interests and non-operated working interests in the state. As of December 31, 2018 , our Arkoma Basin properties consisted of 186,272 gross ( 78,149 net) leasehold acres. During 2018 , the Arkoma Basin properties produced approximately 14,629 MMcfe,

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of which 93% was natural gas. At December 31, 2018 , the properties had total proved reserves of approximately 119,761 MMcfe or 11% of our total estimated proved reserves at year end, of which 100% were proved developed and 91% were natural gas.

Gulf Coast Basin Properties

Our Gulf Coast Basin properties include properties in the onshore Gulf Coast area, North Louisiana, Alabama, East Texas and South Texas.

Production from our North Louisiana properties comes from the East Haynesville and Cotton Valley fields. These properties include multiple productive zones including Cotton Valley, James Lime, Pettet, Haynesville, Smackover and Hosston. East Haynesville is located in Claiborne Parish, Louisiana and lies at a depth of approximately 9,000 to 11,000 feet. The Cotton Valley field is located in Webster Parish, Louisiana and produces from an average depth of 11,000 feet.

Our Alabaman properties include the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet. The Fanny Church field is located two miles east of Big Escambia Creek. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. The Smackover and Norphlet reservoirs are sour gas condensate reservoirs that produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Company-operated Big Escambia Creek Treating facility and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Creek Gas Processing facility. The operation of the wells and the facility is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

Our East Texas producing properties include the Fairway (James Lime Unit) field in Henderson and Anderson counties and produces from an average depth of 10,000 feet.

Our South Texas properties primarily are located in Hidalgo, LaSalle, Live Oak and Webb Counties. Most of the production is high Btu gas that is produced from the Vicksburg, Wilcox, Olmos and Escondido sand formations from a depth ranging from 7,500 to 17,000 feet.

As of December 31, 2018 , our Gulf Coast Basin properties consisted of 148,653 gross ( 63,287 net) leasehold acres. During 2018 , the Gulf Coast Basin properties produced approximately 10,203 MMcfe, of which 54% were oil, condensate and NGLs. At December 31, 2018 , these properties accounted for approximately 98,407 MMcfe or 9% of our total estimated proved reserves at year end, of which 100% were proved developed and 45% were natural gas.

Big Horn Basin Properties

The Big Horn Basin is a prolific basin that is characterized by oil and natural gas fields with long production histories and multiple producing formations.

Our Elk Basin field is located in Park County, Wyoming and Carbon County, Montana. We operate all of our properties in the Elk Basin area, which includes the Embar-Tensleep, Madison and Frontier formations as discussed below.

Embar-Tensleep Formation . Production in the Embar-Tensleep formation is being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Currently, we still use flue gas injection to maintain and improve production within this formation and have recently initiated a fresh water injection pilot on top of the structure. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 5,100 to 6,600 feet.

 

Madison Formation .  We continue to operate an active water injection program that is used to enhance production in the Madison formation. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,400 to 7,000 feet.

Frontier Formation.   The Frontier formation is being produced through primary recovery techniques. The wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,400 to 2,700 feet.

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We operate and own a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation (“Exxon”) owns a 34% interest in this processing plant, and other parties own the remaining 4% interest. This plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from Elk Basin fields.

We also operate and own the Wildhorse pipeline system, which is an approximately 6-mile natural gas gathering system that transports approximately 0.5 MMcf/day of low-sulfur natural gas from the South Elk Basin fields to the Elk Basin natural gas processing plant.

Our Big Horn Basin properties are comprised of assets in Wyoming and the Elk Basin field in south central Montana. We own working interests ranging from 25% to 100% in our Big Horn Basin properties, which consisted of 24,512 gross ( 15,632 net) leasehold acres as of December 31, 2018 . During 2018 , our properties in the Big Horn Basin produced approximately 5,578 MMcfe, of which 86% was oil. At December 31, 2018 , the Big Horn Basin properties accounted for approximately 90,845 MMcfe, or 8% of our total estimated proved reserves at year end, of which 100% were proved developed and 96% were oil, condensate and NGLs.

Anadarko Basin Properties

The Anadarko Basin consists of operated and non-operated properties in the Verden field and other fields located in the Anadarko Basin of western Oklahoma and the Texas Panhandle. Within the Anadarko Basin, our assets can generally be characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Properties in the Anadarko Basin include mature fields with long production histories.

As of December 31, 2018 , our Anadarko Basin properties consisted of 99,805 gross ( 26,673 net) leasehold acres. During 2018 , the Anadarko Basin properties produced approximately 2,407 MMcfe, of which 61% was natural gas. At December 31, 2018 , these properties accounted for approximately 26,089 MMcfe, or 2% of our total estimated proved reserves at year end, of which 100% were proved developed and 66% were natural gas.

Wind River Basin Properties

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch. Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Tallgrass Interstate Gas Transmission and Colorado Interstate Gas (“CIG”). As of December 31, 2018 , our Wind River Basin properties consisted of 71,296 gross ( 46,789 net) leasehold acres. During 2018 , our Wind River Basin properties produced approximately 2,581 MMcfe, of which 85% was natural gas. At December 31, 2018 , the properties had total proved reserves of approximately 23,676 MMcfe, or 2% of our total estimated proved reserves, of which 100% were proved developed and 84% were natural gas.

Powder River Basin Properties

The Powder River Basin is primarily located in northeastern Wyoming. Our development operations are conducted in our coalbed methane (“CBM”) fields. CBM wells are drilled to 1,500 feet on average, targeting the Big George Coals, typically producing water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a CBM well can range from five to eleven years depending on the coal seam. Our natural gas production in this basin is gathered through gathering and pipeline systems owned by Powder River Midstream, Fort Union Gas Gathering, LLC and Thunder Creek Gas Services, LLC. As of December 31, 2018 , our Powder River Basin properties consisted of 114,287 gross ( 66,866 net) leasehold acres. During 2018 , the properties produced approximately 5,480 MMcfe, which was 100% natural gas. At December 31, 2018 , the properties had total proved reserves of approximately 16,609 MMcfe or 2% of our total estimated proved reserves at year end, of which 100% were proved developed and 100% were natural gas.

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Oil, Natural Gas and NGLs Prices

We analyze the prices we realize from sales of our oil, natural gas and NGLs production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. Our natural gas production is primarily sold under market sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The West Texas Intermediate Cushing (“WTI”) price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is mainly determined by its quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees of API (“American Petroleum Institute”) gravity and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted.  Because title of the natural gas sold under these contracts passes at the outlet of the processing plant, we report residue volumes of natural gas in Mcf as production. 

The average realized prices described below include deductions for gathering, transportation and processing fees; however, these prices do not include the impact of our hedges.

Production in the Green River Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed natural gas in the Pinedale field is subject to a processing agreement with Western Gas Resources in their Granger Plant facility where we take our residue natural gas in-kind for sales and NGLs are taken in-kind and sold pursuant to a liquids purchase agreement. During 2017, we were able to renegotiate this processing agreement, lowering our fees significantly. We market our Green River Basin residue natural gas into the Rockies market through the use of multiple pipeline connections. During 2018 , we received the average NYMEX price less $0.81 per Mcf of natural gas in the Green River Basin. Through our renegotiated processing agreement in the Pinedale field, we are given the opportunity to work directly with the plant to decide whether or not it is best to reject or recover ethane (C2). As of December 31, 2018, we expect to continue ethane rejection in Pinedale through 2019.

Production in the Piceance Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed gas is subject to a processing agreement with Enterprise Gas Processing LLC in their Meeker Plant facility. We market our natural gas production into the Rockies market at the Northwest Rockies index pricing. During 2018 , we received the average NYMEX price less $1.09 per Mcf of natural gas in the Piceance Basin.

In the Permian Basin, most of our natural gas production is casinghead natural gas produced in conjunction with our oil production. Casinghead gas typically has a high Btu content and requires processing prior to sale to third parties. We have a number of processing agreements in place with gatherers/processors of our casinghead natural gas, and we share in the revenues associated with the sale of NGLs resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2018 , we received the average NYMEX price less $1.79 per Mcf of natural gas in the Permian Basin. Our oil production is sold under month-to-month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2018 , we received the average NYMEX price less $13.05 per barrel of crude oil in the Permian Basin.

Our Arkoma Basin production in the southeastern Oklahoma Woodford Shale consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities with the processed natural gas ultimately delivered to the Targa Resources, Inc. natural gas processing complex. The processed natural gas is subject to a processing agreement with Targa Resources, Inc., where we take our residue natural gas in-kind for sales, and NGLs are sold pursuant to the terms of that processing agreement. We are contractually provided the ability to make an election to recover or reject ethane (C2) in order to improve product economics. During 2018, we elected to reject ethane, and expect to continue ethane rejection through 2019. The lean natural gas is primarily delivered directly to market. The natural gas was marketed at an Enable East index. For the year ended December 31, 2018 , we received the average NYMEX price less $1.17 per Mcf of natural gas.

In the Gulf Coast Basin, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Our proportionate share of the natural gas volumes are sold at the tailgate of the processing plant at the Houston Ship

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Channel and Waha Gas index pricing that typically results in a discount to NYMEX prices. For the year ended December 31, 2018 , we received the average NYMEX price plus $0.13 per Mcf of natural gas.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections with other pipelines.  Our Big Horn Basin sweet crude oil production is transported from the field by a third-party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. During 2018 , we received the average NYMEX price less $20.80 per barrel of crude oil in the Big Horn Basin.

Our Anadarko Basin production in Oklahoma consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third parties. The lean natural gas is gathered by Enable Gathering & Processing LLC and sold to market at Enable Oklahoma Intrastate Transmission LLC’s West pool at the Panhandle, TX-Okla. index pricing. The high Btu gas is sold at the wellhead to various third parties. The majority is sold to Oneok Field Services Company LLC and DCP Midstream LP under gas purchase contracts subject to percent of proceeds pricing for all products. During 2018 , we received the average NYMEX price less $1.47 per Mcf of natural gas in the Anadarko Basin.      

Our Wind River Basin properties are predominantly natural gas plays with approximately two-thirds of the production being processed at natural gas plants for the extraction of NGLs at our election. Our residue natural gas is sold into the Rockies market at the CIG index price while the NGLs are sold to a third-party natural gas processor pursuant to a processing agreement.

Our Powder River natural gas production is classified as CBM gas and, as it is a very dry gas, is sold directly into the market upon being handled with conventional separation, treating and transportation. In 2017, we were able to renegotiate our current gathering agreement to allow for lower rates, effective December 1, 2017. The CBM gas is sold into the Rockies market at the CIG index price as well. During 2018 , we received the average NYMEX price less $1.17 per Mcf of natural gas in the Wind River Basin while we received the average NYMEX price less $2.00 per Mcf of natural gas in the Powder River Basin.

Oil, Natural Gas and NGLs Data

Estimated Proved Reserves

 

The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2018 , as estimated by our internal reservoir engineers. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency. The standardized measure value shown in the table is not intended to represent the current market value of our estimated oil, natural gas and NGLs reserves. Please read “Reserves Estimation Process” below and the “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our estimated proved reserves.

 

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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 unweighted average of first-day-of-the-month price, the “12-month average price”, and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows.

(2)

Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the 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.

(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 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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The following tables set forth certain information with respect to our estimated proved reserves by operating basin as of December 31, 2018 :

		Estimated Proved Developed Reserve Quantities												PV-10 Value (1)
		Natural Gas (Bcf)			Oil (MMBbls)			NGLs (MMBbls)			Total (Bcfe)			Developed
Operating Basin														(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.

The data in the above table represents estimates only. Oil, natural gas and NGLs reservoir engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future sales prices may differ from those assumed in these estimates. Please read “Item 1A. Risk Factors.”

 

Our internal reservoir engineers’ estimates of future net revenues from our properties, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions using the unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2018 for each product.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The PV-10 and standardized measure disclosed in this Annual Report should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board’s (“FASB”) ASC, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to the timing of future production, which may prove to be inaccurate.

Proved Undeveloped Reserves

As of December 31, 2018 , the Company has removed all proved undeveloped reserves from its total proved reserve estimate due to uncertainty regarding its ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves. The following table represents a summary of our proved undeveloped reserves activity during the year ended December 31, 2018 . This activity includes updates to prior proved undeveloped

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reserves, and the impact of changes in economic conditions, including changes in commodity prices and the uncertainty regarding our ability to continue as a going concern.

	Bcfe
Proved Undeveloped Reserves at January 1, 2018	596.2
Divestitures	(1.0	)
Conversion to developed	(68.4	)
Proved Undeveloped Reserves reclassified to contingent resources	(526.8	)
Proved Undeveloped Reserves at December 31, 2018	—

Divestitures. During the year ended December 31, 2018, our proved undeveloped reserves decreased due to divestitures of oil and gas properties including 1.0 Bcfe of our total proved undeveloped reserves booked as of December 31, 2017.

Conversions. During the year ended December 31, 2018, we developed approximately 68.4 Bcfe of our total proved undeveloped reserves booked as of December 31, 2017 through the drilling of 142 gross (34.1 net) wells.

Revisions/Reclassifications: At December 31, 2018, we reclassified 526.8 Bcfe of proved undeveloped reserves to the contingent resource category. Contingent resources are resources that are potentially recoverable, but not yet considered mature enough for development due to technological or capital restraints. Because substantial doubt exists about our ability to continue as a going concern, in determining year-end 2018 reserves amounts, we concluded we lacked the required degree of certainty about our ability to fund a development drilling program and the availability of capital resources that would be required to develop proved undeveloped reserves. As a result of our inability to meet the reasonable certainty criteria for recording these proved undeveloped reserves as prescribed by the SEC, we did not record any proved undeveloped locations in the December 31, 2018 reserve report.

This year, because substantial doubt exists about our ability to continue as a going concern, we can no longer support our proved undeveloped reserves, due to uncertainty that we have the ability to fund a development plan. Therefore, as of December 31, 2018, we reclassified all of our proved undeveloped reserves to contingent resources.

Reserve Estimation Process

Estimates of proved reserves at December 31, 2018 disclosed in this Annual Report, including proved reserve volumes, PV-10 and the standardized measure of future net cash flows, were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. Our reserve estimation process is a collaborative effort coordinated by our reservoir engineers in compliance with our internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, natural gas and NGLs prices, production costs, future capital expenditures and our net ownership percentages are obtained from other departments within the Company. Our internal reservoir engineers perform review procedures with respect to such non-technical inputs. Reserve variances are discussed among the internal reservoir engineers and the Vice President of Subsurface and Development.

We use technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, production data, well test data, geologic maps, electrical logs and radioactivity logs. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Our reservoir engineering group is directly responsible for our reserve evaluation process and consists of six professionals, three of whom hold, at a minimum, bachelor’s degrees in engineering. Within our Company, our Vice President of Subsurface and Development and our Reservoir Engineering Manager are the technical people primarily responsible for overseeing the preparation of the reserve estimates. Our Vice President of Subsurface and Development has over 28 years of experience and graduated from University of Wyoming with a Bachelor of Science Degree in Petroleum Engineering. Our Reservoir Engineering Manager has over 30 years of experience and graduated from the University of Wisconsin-Milwaukee with a Master of Science Degree in Geology/Geophysics.

 

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The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers .

Independent Audit of Reserves

We engage independent petroleum engineers to audit our reserve estimates. Our internal policies and procedures require the independent engineers to prepare their own estimates of proved reserves for properties comprising at least 80% of our year-end proved reserves. The Board of Directors of the Company (the “Board”) requires that the independent petroleum engineers’ estimate of reserve quantities for the properties audited by the independent petroleum engineers are within 10% of our internal estimate. Once completed, our internally prepared year-end reserve estimates are presented to senior management, including the President and Chief Executive Officer and the Chief Financial Officer for approval.

For the year ended December 31, 2018 , we engaged Miller and Lents, an independent petroleum engineering firm, to perform reserve audit services. The opinion by Miller and Lents for the year ended December 31, 2018 covered producing areas containing 100% of our proved reserves on a net-equivalent-barrel-of-oil basis. Miller and Lents’ opinion indicates that the estimates of proved reserves related to our oil and natural gas properties prepared by our internal reservoir engineers and reviewed by Miller and Lents, when compared in total on a net-gas-equivalent basis, do not differ materially from the estimates prepared by Miller and Lents. Such estimates by Miller and Lents in the aggregate were within our 10% variation tolerance when compared to those prepared by our reservoir engineering group. The report prepared by Miller and Lents was developed utilizing geological and engineering data that we provided. The report of Miller and Lents dated March 5, 2019, which contains further discussion of the reserve estimates and evaluations prepared by Miller and Lents, as well as the qualifications of Miller and Lents’ technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report and incorporated herein by reference.

Within Miller and Lents, the lead technical person primarily responsible for overseeing the audit of our reserves is Ms. Leslie A. Fallon. Ms. Fallon is a Senior Vice President with Miller and Lents and has over 30 years of experience in oil and gas reservoir studies and reserves evaluations. She graduated from the University of Texas at Austin in 1983 with a Bachelor of Science Degree in Mechanical Engineering and is a licensed Professional Engineer in the State of Texas. Ms. Fallon meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

During 2018 , we paid fees of approximately $0.4 million to independent petroleum engineers for all reserve and economic evaluations.

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated. Information for fields with greater than 15% of our total proved reserves have been listed separately in the table below for the years ended December 31, 2018, 2017, and 2016, respectively.

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		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).

Productive Wells

The following table sets forth information at December 31, 2018 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

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		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 and Undeveloped Leasehold Acreage

The following table sets forth information as of December 31, 2018 relating to our leasehold acreage.

 

		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.

Substantially all of our developed and undeveloped leasehold acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The leases in which we hold an interest that is not held by production are not material to us because these leases have no proved undeveloped reserves assigned.

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Drilling Activity

The following is a description of the Company’s drilling and completion activities during the year ended December 31, 2018 .

In the Green River Basin, we participated in the drilling of 145 gross wells (19.4 net) and the completion of 131 gross wells (17.8 net) in Sublette County in southwestern Wyoming. These wells are directionally drilled from pads but are vertical through the 5,000 feet pay section. The average well depth is approximately 14,000 feet and is typically completed with 14 to 20 frac stages.

In the Piceance Basin, we drilled and completed 14 gross (13.9 net) operated wells in the Mamm Creek field in Garfield County, Colorado. These wells are directionally drilled from pads but are vertical through the 2,500 feet pay section. The average well depth is approximately 8,000 feet and is typically completed with 8 frac stages.

In the Permian Basin, we participated in the drilling and completion of 13 gross horizontal wells (0.2 net) in Eddy County, New Mexico. We also participated in the drilling and completion of one horizontal well in Yoakum County, Texas with an 8% working interest. The horizontal wells were drilled to vertical depths of 7,000 to 9,000 feet and extended with horizontal lateral lengths of approximately 7,000 to 10,000 feet.

In the Arkoma Basin, we participated in the drilling of 14 gross (1.8 net) wells and the completion of 12 gross (0.7 net) wells in Coal, Pittsburg and Hughes counties in Oklahoma. These wells were drilled to vertical depths of 7,000 to 10,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet.

In the Gulf Coast Basin, we drilled and completed one operated vertical well with a 100% working interest in Claiborne County, Louisiana. We also participated in the drilling of five (0.5 net) wells and completed one (0.3 net) well in Webster and De Soto Counties, Louisiana. Three of these wells are directionally drilled from pads but are vertical through the 500 to 1,000 feet pay section. The average well depth is approximately 10,000 feet and is typically completed with 2 to 3 frac stages. The remaining three wells are horizontally drilled to vertical depths of 10,000 feet to 13,000 feet and extended with horizontal lateral lengths of approximately 8,000 feet to 10,000 feet.

In the Big Horn Basin, we drilled and completed one gross (0.6 net) operated well in Carbon County, Montana. The well is directionally drilled from a pad but is vertical through the 400 feet pay section. The average well depth is approximately 6,500 feet and is typically completed with 2 frac stages.

In the Anadarko Basin, we participated in the drilling of five gross (0.2 net) horizontal wells and the completion of four gross (0.1 net) horizontal wells in the Cleveland field in Ellis and Dewey counties in Oklahoma. These wells were drilled to vertical depths of 8,000 to 13,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 7,000 feet.

In the Powder River Basin, we drilled and completed six gross (6.0 net) operated vertical wells in Campbell and Johnson counties in Wyoming. These wells were drilled to vertical depths of 1,000 to 2,000 feet.

The Board approved, subject to the approval of the DIP Agent and the agent under the Successor Credit Facility, a capital expenditures budget for 2019 of approximately $53.0 million compared to the $124.9 million we spent in 2018 . Our 2019 capital expenditures budget includes approximately $24.0 million of drilling and completion capital focused on the core growth assets of the Green River and Arkoma Basins. If our 2019 capital expenditure budget is approved by the DIP Agent and the agent under the Successor Credit Facility, we expect to spend approximately $15.0 million of the drilling capital budget in the Arkoma Basin where we will participate as a non-operated partner in the drilling and completion of horizontal wells targeting the Woodford and Mayes formations. This program is a continuation of our 2018 one rig program with Newfield Exploration Company, (“Newfield”). The acquisition of Newfield by Encana Corporation has delayed the completion of the program. However, we anticipate further evaluation of the scope and timing of this project to recommence later this fiscal year. Furthermore, we expect to spend approximately $9.0 million in the Green River Basin at the Pinedale field where we participate as a non-operated partner in the drilling of vertical natural gas wells with Ultra Petroleum Corporation and Pinedale Energy Partners. In addition to our drilling and completion programs, we expect to spend approximately $8.0 million on other uplift projects, primarily in the Permian New Mexico Red Lake field, where we will expand on our successful 2018 operated Yeso recompletion and commingle program. The remaining $21.0 million of the capital program will be spent on maintenance and land projects that include safety and environmental compliance, compressor overhauls, facility work, returning wells to production that go offline during the year and other capital required to maintain reserves and operations.

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The following table sets forth information with respect to wells completed during the years ended December 31, 2018 , 2017 and 2016 . Our drilling activity during these periods has consisted entirely of drilling development wells. We have not drilled any exploratory wells during these periods. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil, natural gas, and NGLs regardless of whether they produce a reasonable rate of return.

		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

Operations

 

Principal Customers

For the year ended December 31, 2018 , sales of oil, natural gas and NGLs to Mieco Inc. , Exxon , Plains Marketing, L.P. , Macquarie Energy and ConocoPhillips accounted for approximately 14% , 7% , 6% , 6% and 5% , respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2018 therefore accounted for 38% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash flows from operations could decline. However, if we were to lose a customer, we believe a substitute purchaser could be identified in a timely manner and upon similar terms and conditions.

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Delivery Commitments and Marketing Arrangements

Our oil and natural gas production is principally sold to marketers, processors, refiners and other purchasers that have access to nearby pipeline, processing and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area and generally are month-to-month or have terms of one year or less.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with credit-worthy purchasers, including independent marketing companies, gas processing companies and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas production from our operated properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices, but we are also subject to any future price declines, subject to the impact of derivatives. We do market our own natural gas on some of our non-operated properties.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other export pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third-party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. We sell oil production from our operated Permian Basin properties at the wellhead to third-party gathering and marketing companies.

Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we may enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. Currently, a majority of our existing firm transportation agreements were assumed in connection with acquisitions of oil and natural gas properties. These agreements have term delivery commitments of fixed and determinable quantities of natural gas. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” for additional information regarding our long-term firm transportation contracts.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity, which typically require a demand charge. We source the gas to meet these commitments from our producing properties. We have certain commitments that we assumed as part of our acquisitions of oil and gas properties where the production from the acquired properties and the production of joint interest owners that we market were not adequate to meet the commitments resulting in us paying the set demand charge relating to the maximum daily quantity outlined in the contract. For further information related to these demand charges, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Commitments and Contractual Obligations” and Note 10 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report. During the year ending December 31, 2019, our firm transportation contract obligates us to deliver 25,000 MMBtu of natural gas per day.

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

Price Risk Management Activities

We routinely enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps and collars to hedge oil and natural gas prices. By removing the price volatility from a significant portion of our oil and natural gas production, we are able to mitigate for a period of time, but not eliminate, the potential effects of fluctuation in oil and natural gas prices on our cash flow from operations. For a description of our derivative positions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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Competition

 

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff substantially larger than ours or a different business model. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for, purchase, or develop a greater number of properties or prospects than our financial, technical or personnel resources will permit.

 

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development program.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure stockholders that we will be able to compete satisfactorily when attempting to make future acquisitions.

 

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We will generally not commence drilling operations on a property until we believe we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our oil and natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in the Gulf Coast Basin, Piceance Basin and Big Horn Basin. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

•	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.

Seasonal Nature of Business

Seasonal weather conditions, severe weather events, and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increased costs or delay our operations. Generally, but not always, oil is typically in higher demand in the late summer due to the summer driving season, which results in increased gasoline and diesel usage and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as hot summers or mild winters, which are unpredictable, sometimes impact this fluctuation. In

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addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

 

Environmental and Occupational Health and Safety Matters

General.   Our business involving the acquisition and development of oil and natural gas properties is subject to extensive and stringent federal, state and local laws and regulations governing environmental protection and the health and safety of employees. Our operations are subject to the same environmental, health and safety laws and regulations as other similarly situated companies in the oil and natural gas industry. These laws and regulations may:

 

•	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.

Failure to comply with these laws and regulations may result in the assessment of significant sanctions, including administrative, civil and criminal penalties, imposition of remedial obligations, and the issuance of orders enjoining some or all of our operations deemed in non-compliance. Moreover, these laws and regulations may restrict our ability to produce oil, natural gas and NGLs by, among other things, limiting production from our wells, limiting the number of wells we are allowed to drill or limiting the locations at which we may conduct our drilling operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects profitability. Additionally, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly well drilling, construction, completion and water management activities, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs. We believe that operation of our wells is in substantial compliance with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot provide any assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition, and results of operations. For the year ended December 31, 2018 , we did not incur any material capital expenditures for performance of remediation or installation of pollution control equipment at any of our facilities; however, we did incur capital expenditures in the ordinary course of business to comply with pollution control requirements. As of the date of this Annual Report, we are not aware of any environmental issues or claims that will likely require material capital expenditures during 2019 or that will otherwise have a material adverse impact on our financial position or results of operations.

 

The following is a summary of the more significant existing environmental and occupational health and safety laws to which our business operations are subject and for which compliance may have a material adverse impact on our operations as well as the oil and natural gas exploration and production industry in general.

 

Waste Handling.   The Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state laws, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” as well as the disposal of non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or the “U.S. EPA,” individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent state requirements. Drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy are currently regulated under RCRA’s less stringent non-hazardous waste provisions. However, the U.S. EPA has assessed whether to amend the existing RCRA regulations to re-classify certain oil and natural gas exploration and production wastes as hazardous wastes. Any such change could increase our costs to manage and dispose of such generated wastes,

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which cost increase could be significant. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as RCRA hazardous wastes.

 

  Hazardous Substance Releases.    The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA,” or “Superfund,” and analogous state laws, impose joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported or disposed or arranged for the transportation or disposal of the hazardous substance found at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While materials are generated in the course of operation of our wells that may be regulated as hazardous substances, we have not received any pending notifications that we may be potentially responsible for cleanup costs under CERCLA.

 

We currently own, lease, or have a non-operating interest in numerous properties that have been used for oil and natural gas production for many years. Although we believe that operating and waste disposal practices used on these properties in the past were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where these substances, wastes and hydrocarbons have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

As of December 31, 2018 , we have recorded $4.5 million for future remedial costs and abandonment liability for decommissioning the Big Escambia Creek, Elk Basin, and Fairway natural gas processing plants.

•

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.

Our estimates of the future remediation cost are subject to change, and the actual cost of these items could vary significantly from the above estimates. Due to the significant uncertainty associated with the known environmental liabilities at the gas plants, our estimate of the future abandonment liability includes a reserve.

Pipeline Safety.   The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, state agencies, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to the Company’s pipelines. These determinations may affect the costs the Company incurs in complying with applicable safety regulations.

Water Discharges.   The Federal Water Pollution Control Act, as amended, or “Clean Water Act,” and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into state waters as well as waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by U.S. EPA or the relevant state with delegated authority. The Clean

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Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by an appropriately issued permit. The EPA and the U.S. Army Corps of Engineers released a rule to revise the definition of “waters of the United States,” or WOTUS, for all Clean Water Act programs, which went into effect in August 2015. The EPA has instituted rulemakings to both delay the effective date of this rule and repeal the rule. Federal district court decisions have preserved the stay in a majority of states, which remain subject to pre-2015 regulated waters regulations, whereas the stay has been enjoined in a minority of states. Litigation surrounding this rule is ongoing. More recently, on December 11, 2018, the EPA and the Corps released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of waters of the United States; the revised rule has not yet been finalized. Spill prevention, control and countermeasure, or “SPCC,” requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by an oil spill or release. If an oil spill or release were to occur as a result of our operations, we expect that it would be contained and remediated in accordance with our SPCC plan together with the assistance of trained first responders and any oil spill response contractor that we may have engaged to address such spills and releases. The Clean Water Act and analogous state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in below ground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control, or UIC, program established under the federal Safe Drinking Water Act, or SDWA, and analogous state laws. The UIC program requires permits from U.S. EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into below ground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission, or TRC, published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that are the site of a release of oil into waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Hydraulic Fracturing.   Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years. From time to time Congress has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Federal agencies have asserted regulatory authority over certain aspects of the process. Although the U.S. EPA and the federal Bureau of Land Management (“BLM”) have taken several steps to federalize regulation of hydraulic fracturing, more recently under the current Administration, the U.S. EPA and BLM have limited such steps. For example, the U.S. EPA issued Clean Air Act rules governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, but the effective date of which was delayed and a proposed rule to reconsider was issued in September 2018. In June 2016, U.S. EPA issued final rules establishing effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant, although the effective date of which has also recently been delayed and the rule is subject to legal challenge. Separately, in March 2015, BLM issued a final rule that imposes requirements on hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water. BLM rescinded this rule in December 2017. In January 24, 2018, California and a coalition of

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environmental groups each filed lawsuits in the Northern District of California to challenge BLM’s rescission of the 2015 rule. This litigation is pending.

Some states in which the Company operates, including Montana, Texas and Wyoming, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

  

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability and control of well insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions.    The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and their implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with air permit requirements containing various emissions and operational limitations, or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no significant difficulties have been encountered in obtaining air permits. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air control equipment in connection with obtaining and maintaining operating permits and approvals for emissions of pollutants. For example, in October 2015, U.S. EPA issued a final rule that strengthened the National Ambient Air Quality Standard, or “NAAQS,” for ozone from 75 parts per billion, or “ppb,” to 70 ppb for both the 8-hour primary and secondary standards. The U.S. EPA finalized revising the designation of attainment and non-attainment air quality control regions based on the new ozone standard. If regions reclassified as non-attainment under the lower ozone standard begin implementing new, more stringent regulations, those regulations could apply to our or our customers’ operations. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Activities on Federal Lands .  Oil and natural gas exploitation and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current production activities, as well as proposed development plans, on federal lands require governmental permits or similar authorizations that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay, limit, or halt projects.

Climate Change .  In response to findings made by U.S. EPA that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, U.S. EPA has adopted regulations under the Clean Air Act that establish Title V operation and Prevention of Significant Deterioration, or “PSD,” construction permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which typically will be established by the states. These U.S. EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, U.S. EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. We are conducting monitoring of GHG emissions from our operations in accordance with the

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GHG emissions reporting rule and we believe that our monitoring and reporting activities are in substantial compliance with applicable reporting obligations. In October 2015, the EPA finalized the Clean Power Plan, which imposes additional obligations on the power generation sector to reduce GHG emissions. However, on February 9, 2016, the U.S. Supreme Court stayed implementation of the Clean Power Plan pending resolution of legal challenges to the rule, and in October 2017 the EPA proposed to repeal the rule before proposing a replacement rule, the Affordable Clean Energy Rule, which would scale back the obligations of the Clean Power Plan.

While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. In June 2017, the Trump administration announced its intention for the United States to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest date the United States can withdraw is November 2020. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. For example, on June 3, 2016, U.S. EPA published a Methane Rule aimed at reducing methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. However, on June 16, 2017, U.S. EPA proposed to delay the Methane Rule’s effectiveness for two years from the final rule’s publication. In September 2018, the U.S. EPA issued a proposed rule that would reconsider limits on methane emissions set by the June 2016 standards and reduce inspection and repair requirements.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Endangered Species Act Considerations.   Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, wetlands and natural resources. These statutes include the Endangered Species Act (“ESA”) and the Clean Water Act.   

If endangered or threatened species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, the government could seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA.

Occupational Safety and Health.   We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, U.S. EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

  

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules,

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orders and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. For example, on July 1, 2014, the North Dakota Industrial Commission adopted Order No. 24665, or the “July 2014 Order,” pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the State by October 1, 2014, 77% percent of such gas by January 1, 2015, 85% of such gas by January 1, 2016 and 90% of such gas by October 1, 2020. The July 2014 Order establishes an enforcement mechanism for policy recommendations that were previously adopted by the North Dakota Industrial Commission in March 2014. Those recommendations required all exploration and production operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s now-implemented gas capture percentage goals. In particular, the July 2014 Order provides that after an initial 90-day period, wells must meet or exceed the North Dakota Industrial Commission’s gas capture percentage goals on a per-well, per-field, county, or statewide basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured. While we believe that we were in compliance with these requirements as of December 31, 2018 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in compliance in the future or that such future compliance will not have a material adverse effect on our business and operational results. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Drilling and Production.    Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

•	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.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil, natural gas and NGLs we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

 

Regulation of Transportation and Sales.    The availability, terms and cost of transportation significantly affect sales of oil, natural gas and NGLs. The interstate transportation of natural gas is subject to federal regulation primarily by the Federal Energy Regulatory Commission, or “FERC,” under the Natural Gas Act of 1938, or “NGA.”  FERC regulates interstate natural gas pipeline transportation rates and service conditions, which may affect the marketing and sales of natural gas.  FERC requires interstate pipelines to offer available firm transportation capacity on an open-access, non-discriminatory basis to all natural gas shippers.  FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry.  State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis and are subject to state ratable take and common purchaser statutes.  Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

The ability to transport oil and NGLs is generally dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, or subject to regulation by the particular state in which such

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transportation takes place.  Laws and regulation applicable to pipeline transportation of oil largely require pipelines to charge just and reasonable rates published in agency-approved tariffs and require pipelines to provide non-discriminatory access and terms and conditions of service. The justness and reasonableness of interstate oil and natural gas liquid pipeline rates can be challenged at FERC through a protest or a complaint and, if such a protest or complaint results in a lower rate than that on file, pipeline shippers may be eligible to receive refunds or, in the case of a complaining shipper, reparations for the two-year period prior to the filing of the complaint. Certain regulations imposed by FERC, by the United States Department of Transportation and by other regulatory authorities on pipeline transporters in recent years could result in an increase in the cost of pipeline transportation service.  We do not believe, however, that these regulations affect us any differently than other producers.

Under the Energy Policy Act of 2005, or “EPAct 2005,” Congress made it unlawful for any entity, as defined in the EPAct 2005, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act up to $1,000,000 per day per violation. Pursuant to authority granted to FERC by EPAct 2005, FERC has also put in place additional regulations intended to prevent market manipulation and to promote price transparency.  For example, FERC has imposed rules discussed below requiring wholesale purchasers and sellers of natural gas to report to FERC certain aggregated volume and other purchase and sales data for the previous calendar year. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by EPAct 2005 any differently than energy industry participants.

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report on Form No. 552, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Pursuant to Order 704, we may be required to annually report to FERC, starting May 1 of each year, information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year. In recent years, FERC has also issued rules prohibiting anticompetitive behavior by multiple affiliates of the same entity in the natural gas capacity release market, issued a policy statement providing natural gas pipelines a cost-recovery mechanism to recoup capital expenditures made to modernize pipeline infrastructure, and issued a rule adopting reforms to its scheduling rules to improve coordination between the natural gas and electric markets.

On August 6, 2009, the Federal Trade Commission, or “FTC,” issued a Final Rule prohibiting manipulative and deceptive conduct in the wholesale petroleum markets. The Final Rule applies to transactions in crude oil, gasoline, and petroleum distillates. The FTC promulgated the Final Rule pursuant to Section 811 of the Energy Independence and Security Act of 2007, or “EISA,” which makes it unlawful for anyone, in connection with the wholesale purchase or sale of crude oil, gasoline or petroleum distillates, to use any “manipulative or deceptive device or contrivance, in contravention of such rules and regulations as the Federal Trade Commission may prescribe.” The Final Rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from: (a) knowingly engaging in any act, practice, or course of business – including making any untrue statement of material fact that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. Sales of condensate and NGLs are not currently regulated and are made at market prices. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the

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Commodity Futures Trading Commission, or “CFTC.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. 

Although natural gas and oil prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

State Regulation .  The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGLs, including imposing severance and other production-related taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not currently regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGLs that may be produced from our wells, to increase our cost of production, to limit the number of wells or locations we can drill and to limit the availability of pipeline capacity to bring our products to market.

In addition to production taxes, Texas, Oklahoma and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming, Colorado and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment.

The petroleum industry participants are also subject to compliance with various other federal, state and local regulations and laws. Some of these regulations and those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these regulations and laws will have a material adverse effect upon the unitholders.

Federal, State or Native American Leases .  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the BLM and other agencies.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. VNR carries business interruption insurance for the Big Escambia Creek, Flomaton, Fairway James, Elk Basin and XTO Cotton Valley processing facilities. VNR also carries contingent business interruption coverage to protect against upstream shut-ins of our Pinedale, Piceance, Permian, Haynesville, and Wind River productions. We insure any cumulative value of owned property over a certain threshold, and carry control of well and pollution coverage for all VNR wells (including new drills and workovers), and re-drill coverage for those that are economically viable. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost.  If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

Employees

As of April 8, 2019 , we had 290 full-time employees. We also contract for the services of independent consultants involved in land, regulatory, tax, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by collective bargaining agreements. We believe that our relations with our employees are satisfactory.

 

Offices

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Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our main telephone number is (832) 327-2255.

Available Information

 

Our website address is www.vnrenergy.com . We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report. We make available on our website under “Investor Center-SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

You may also find information related to our corporate governance, board committees and company code of business conduct and ethics on our website under “Investor Relations - Corporate Governance.” Among the information you can find there is the following:

 

•     Audit Committee Charter;

•     Compensation Committee Charter;

•	Health, Safety, and Environmental Committee Charter;

•     Nominating and Corporate Governance Committee Charter;

•     Insider Trading Policy;

•     Related Party Transactions Policy;

•     Code of Ethics for CEO, CFO and PAO;

•     Code of Business Conduct and Ethics; and

•     Corporate Governance Guidelines.

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ITEM 1A.  RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our Common Stock.

Risks Related to Bankruptcy

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with the 2019 Chapter 11 Cases.

 

We have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the 2019 Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to the following:

•	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.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our 2019 Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the 2019 Chapter 11 Cases. Because of the risks and uncertainties associated with 2019 Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the 2019 Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the 2019 Chapter 11 Cases may have on our corporate or capital structure.

Operating under the protection of the Bankruptcy Court for a long period of time may harm our business.

 

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations in Chapter 11 could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the 2019 Chapter 11 Cases remain pending, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating in Chapter 11 also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the 2019 Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships. Given that this will be our second Chapter 11 bankruptcy filing in two years, the harm to our business may be even more pronounced.

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In addition, so long as the 2019 Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the 2019 Chapter 11 Cases.

Furthermore, we cannot predict how claims and equity interests will be treated under a plan of reorganization. Even once a plan of reorganization is confirmed and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11.

 

We may not be able to obtain confirmation of a Chapter 11 plan.

 

In order to emerge successfully from the 2019 Chapter 11 Cases as a viable entity, we must meet certain statutory disclosure requirements with respect to adequacy of disclosure with respect to a plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a reorganization plan, most of which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our Chapter 11 plan of reorganization. There is no assurance that our Chapter 11 plan of reorganization, when filed, or any subsequent amendments thereto, will be confirmed and become effective.

If a plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims and equity interests against us would ultimately receive with respect thereto.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and there is substantial doubt regarding our ability to continue as a going concern.

 

Even if a Chapter 11 plan of reorganization is consummated, we may continue to face a number of risks, such as further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve our stated goals.

In addition, at the outset of the 2019 Chapter 11 Cases, the Bankruptcy Code gives the 2019 Debtors the exclusive right to propose a plan of reorganization and prohibits creditors, equity security holders and others from proposing a plan. We have currently retained the exclusive right to propose a plan of reorganization. If that right is terminated, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan of reorganization in order to achieve our stated goals.

 

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the 2019 Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

 

As a result of the entry into the 2019 Chapter 11 Cases, there is substantial doubt regarding our ability to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a plan of reorganization is confirmed.

 

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the 2019 Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our 2019 Chapter 11 Cases. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the 2019 Chapter 11 Cases until we are able to emerge from our 2019 Chapter 11 Cases. While we entered into the interim DIP Credit Agreement in connection with the 2019 Chapter 11 Cases, which provides for a multi-draw term loan in an aggregate amount of up to $65.0 million and a $65.0 million Roll-Up, as of the date hereof, we have not received a commitment for any additional interim financing or exit financing.

 

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i)

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our ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the 2019 Chapter 11 Cases, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to borrow under the DIP Credit Agreement, (v) our ability to develop, confirm and consummate a Chapter 11 plan or reorganization or other alternative restructuring transaction, and (vi) the cost, duration and outcome of the 2019 Chapter 11 Cases.

 

As a result of the 2019 Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

During the 2019 Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the 2019 Chapter 11 Cases. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

 

Any Chapter 11 plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

 

Any Chapter 11 plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will be premised upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial projections are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial projections will not be accurate. In our case, the projections will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

 

We may be subject to claims that will not be discharged in the 2019 Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

 

The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to March 31, 2019, or before confirmation of a plan of reorganization (i) would be subject to compromise and/or treatment under a plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of a plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

 

We may experience increased levels of employee attrition as a result of the 2019 Chapter 11 Cases.

 

As a result of the 2019 Chapter 11 Cases, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the 2019 Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members

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of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our business, financial condition and results of operations.

 

We have significant exposure to fluctuations in commodity prices because none of our estimated future production is covered by commodity derivatives and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all.

 

We may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

 

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

 

Upon a showing of cause, the Bankruptcy Court may convert our 2019 Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than would be made to our creditors under Chapter 11 because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

 

The pursuit of the 2019 Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.

 

A long period of operating under Chapter 11 could adversely affect our business and results of operations. While the 2019 Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort focusing on the 2019 Chapter 11 Cases. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the 2019 Chapter 11 Cases are protracted.

During the existence of an event of default and the 2019 Chapter 11 Cases, we have no borrowing capacity under our Successor Credit Facility. Unless we are able to successfully restructure our existing indebtedness we may not be able to continue as a going concern.

Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of borrowings under our Successor Credit Facility, the sale of assets and cash flows from operating activities. We currently have limited access to additional capital. During the existence of an event of default, we have no availability under our Successor Credit Facility.

 

The accompanying Consolidated Financial Statements have been prepared on a going concern basis that contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. Unless we are able to successfully restructure our existing indebtedness under the 2019 Chapter 11 Cases we may not be able to continue as a going concern.

Risks Related to our Business

We have substantial liquidity needs and may not be able to obtain exit financing.

In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our 2019 Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our 2019 Chapter 11 Cases. While we entered into the interim DIP Credit Agreement in connection with the 2019 Chapter 11 Cases, which provides for a multi-draw term loan in an aggregate amount of up to $65.0 million and a $65.0 million Roll-Up, as of the date hereof, we have not received a commitment for any additional interim financing or exit financing. Even if we are able to amend and restate or refinance our the Successor Credit Facility, we do not anticipate any additional liquidity

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we receive from such an amendment and restatement or refinancing to be substantial.

We do not believe that our borrowings under the proposed final DIP Credit Agreement, our cash on hand and our cash flow from operations will be sufficient to continue to fund our operations for any significant period of time. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the 2019 Chapter 11 Cases, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

 

Trading in our securities during the pendency of the 2019 Chapter 11 Cases and after is highly speculative and poses substantial risks .

Trading in our securities during the pendency of the 2019 Chapter 11 Cases and after is highly speculative and poses substantial risks. Trading prices for our securities may bear little or no relationship to the actual recovery, if any, by holders of our securities in the 2019 Chapter 11 Cases. Furthermore, it is probable that our Common Stock and warrants will be cancelled as a result of the 2019 Chapter 11 Cases.

 

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Successor Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Interest Price Risks” for additional information regarding interest rate sensitivity.

Despite our current level of indebtedness, we may still be able to incur more debt. This could further exacerbate the risks associated with our indebtedness, including limiting our liquidity and our ability to pursue other business opportunities.

We may be able to incur additional indebtedness in the future, subject to certain limitations, including under our DIP Facility, the Successor Credit Facility and the Amended and Restated Indenture. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

Further, under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. The 2019 Debtors are subject to various covenants and events of default under our DIP Facility. In general, certain of these covenants limit the 2019 Debtors’ ability, subject to certain exceptions, to take certain actions, including:

•	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.

If the 2019 Debtors fail to comply with these covenants or an event of default occurs under our DIP Facility, our liquidity, financial condition or operations may be materially impacted.

Our current operations and future growth may require significant additional capital, and the amount and terms of our indebtedness could impair our ability to fund our capital requirements. Our DIP Facility may be insufficient to fund our cash requirements through emergence from bankruptcy.

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Our business requires substantial capital. We may require additional capital in the event of growth opportunities, unanticipated maintenance requirements, or significant departures from our current business plan.

Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in our DIP Facility. Failure to obtain additional financing, should the need for it develop, could impair our ability to fund capital expenditure requirements and meet debt service requirements and could have an adverse effect on our business.

Further, for the duration of the 2019 Chapter 11 Cases, we will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund a plan of reorganization and meet future obligations, and (ii) increased legal and other professional costs associated with the 2019 Chapter 11 Cases and our reorganization.

If the transactions contemplated by a plan of reorganization are not completed and the effective date of a plan of reorganization does not occur prior to the maturity of our DIP Facility, we may need to refinance our DIP Facility. We may not be able to obtain some or all of any such financing on acceptable terms or at all.

Disruptions in the capital and credit markets, low oil, natural gas and NGLs prices relative to historical averages and other factors may restrict our ability to raise capital on favorable terms, or at all.

 

Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, have and could continue to limit our ability to access these markets or may significantly increase our cost to borrow. Low oil, natural gas and NGLs prices relative to historical averages, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy, and in certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business and financial condition.

We may be subject to risks in connection with divestitures.

In 2017 and 2018, we completed divestitures of a portion of our non-core assets as discussed in Note 5 to the Notes to the Consolidated Financial Statements in Part II, Item 8. In connection with other future transactions, we may sell our core or non-core assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes. Various factors could materially affect our ability to execute on these strategic alternatives and any contemplated asset divestitures, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms that we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.

Our business plan was prepared using certain assumptions, including with respect to our ability to make certain divestitures and asset dispositions. If the level of divestitures actually completed is less than planned or expected, it may not be satisfactory to us or sufficient for our purposes or requirements.

In addition, sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Oil, natural gas and NGLs prices are volatile due to factors beyond our control and have declined from historical highs. Sustained lower prices or a significant decline in prices of oil, natural gas and NGLs, could have a material adverse impact on us.

    

Our financial condition, profitability and future growth and the carrying value of our oil and natural gas properties depend substantially on prevailing oil, natural gas and NGLs prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. The WTI crude oil spot price per barrel during the years ended December 31, 2017 and 2018 ranged from a low of $42.48 to a high of $77.41 and the Henry Hub natural gas spot price per MMBtu during the same period ranged from a low of $2.44 to a high of $6.24 . NGLs prices also demonstrated similar

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volatility. This price volatility impacted our operating results for the years ended December 31, 2017 and 2018 and contributed to a reduction in capital expenditures for those years. 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 .

The prices for oil, natural gas and NGLs are volatile due to a variety of factors, including, but not limited to:

• the domestic and foreign supply of oil, natural gas and NGLs;

•	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;

• labor unrest in oil and natural gas producing regions;

•	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

• the price and availability of, and demand for, alternative fuels and renewable energy sources;

•	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;

• the price and level of foreign imports;

•	technological advances affecting energy consumption and energy supply;

• worldwide economic conditions;

• market expectations about future prices of oil and natural gas;

• speculation by investors in oil and gas;

• the availability, cost, proximity and capacity of gathering, processing, refining and transportation facilities;

• the cost and availability of products and personnel needed for us to produce oil, natural gas and NGLs;

•	domestic and foreign governmental relations, regulation and taxation, including limits on the United States’ ability to export crude oil; and

• the availability of liquid natural gas imports and exports.

    

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil, natural gas and NGLs; many of our projections and estimates, however, are based on assumptions as to the future prices of oil, natural gas and NGLs. These price assumptions are used for planning purposes. We expect that our assumptions will change over time and that actual prices in the future will likely differ from our estimates.

Sustained lower prices or a significant decline in prices of oil, natural gas and NGLs prices would not only reduce our revenue, but also could reduce the amount of oil, natural gas and NGLs that we can produce economically, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil, natural gas and NGLs properties, all of

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which could have a material adverse effect on our financial condition, results of operations and reserves. In addition, lower oil, natural gas and NGLs prices may result in additional asset impairment charges from reductions in the carrying values of the Company’s oil and gas properties. During the year ended December 31, 2018 , we recorded impairment charges of $29.7 million on our proved properties. Please read Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for additional information.

If the oil and gas industry were to experience a period of declining or sustained low prices in the future, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our Common Stock. Also, lower oil, natural gas and NGLs prices in the future could:

 

•	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.

Our inability to finance the development of our properties, future oil and natural gas price declines and other factors may result in additional write-downs of our asset carrying values.

Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. During 2018, we recorded an impairment of oil and natural gas properties of $29.7 million . We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred. Since December 31, 2018, oil, natural gas and NGLs prices have continued to fluctuate. If oil, natural gas, and NGLs prices significantly decrease in future quarters, we could have additional impairments of our oil and natural gas properties.

We could experience periods of higher costs if oil, natural gas and NGLs prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGLs prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. In late 2014, oil, natural gas and NGLs prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our operating areas. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As oil, natural gas and NGLs prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.

Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations.

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Producing oil and natural gas wells extract hydrocarbons from underground structures referred to as reservoirs. Reservoirs contain a finite volume of hydrocarbon reserves referred to as reserves in place. Based on prevailing prices and production technologies, only a fraction of reserves in place can be recovered from a given reservoir. The volume of the reserves in place that is recoverable from a particular reservoir is reduced as production from that well continues. The reduction is referred to as depletion. Ultimately, the economically recoverable reserves from a particular well will deplete entirely, and the producing well will cease to produce and will be plugged and abandoned. In that event, we must replace our reserves. Unless we are able over the long-term to replace the reserves that are depleted through production, our cash flows from operations, financial condition and results of operations may be adversely affected. We must therefore make substantial capital expenditures to find, acquire, develop and produce new oil and gas reserves. Our ability to make necessary capital expenditures to maintain or expand our asset base of oil and natural gas reserves may be adversely affected to the extent of a reduction in our cash flow from operations, the unavailability of external financing sources and the approval of the Bankruptcy Court.

A widening of commodity differentials and our inability to enter into hedge contracts for a sufficient amount of our production at favorable pricing could materially adversely impact our financial condition, results of operations and cash flows from operations.

Our crude oil, natural gas and NGLs are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil, natural gas and NGLs production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We may not be able to accurately predict crude oil, natural gas and NGLs differentials.

Price differentials may widen in the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, changes in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on NYMEX index prices and the NGLs hedges are based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices, so we may be subject to basis risk if the differential on the products we sell widens from those benchmarks and we do not have a contract tied to those benchmarks. In the past, we have entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive and our inability to enter into hedge contracts at favorable pricing and for a sufficient amount of our production could adversely affect our financial condition, results of operations and cash flows from operations in the future.

Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our financial condition, results of operations and cash flows from operations.

To achieve more predictable net cash provided by operating activities and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into commodity derivative contracts for a portion of our production. Commodity derivative arrangements have and may continue to expose us to the risk of financial loss in some circumstances, including situations when production is less than expected. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the sale of our underlying physical commodity, which may adversely affect our financial condition, results of operations and cash flows from operations.

We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential oil, natural gas and NGLs price uncertainty and could adversely affect our financial condition, results of operations and cash flows from operations.

While we have hedged a portion of our estimated production for 2018 and 2019, our anticipated production volumes remain mostly unhedged. Based on current expectations for future oil, natural gas and NGLs prices, reduced hedging market liquidity and potential reduced counterparty willingness to enter into new hedges with us while under Chapter 11, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential oil, natural gas and NGLs price uncertainty and could adversely affect our financial condition, results of operations and cash flows from operations.

Adverse developments in our operating areas would have a negative impact on our results of operations.

Our properties are located in Wyoming, Colorado, Texas, New Mexico, Louisiana, Montana, Oklahoma and Alabama. An adverse development in the oil and natural gas business of any of these geographic areas, such as in the availability of field

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personnel, equipment and facilities, compliance with governmental regulations, regional supply and demand factors, transportation capacity constraints or adverse weather conditions such as droughts or natural disasters, could have a negative impact on our results of operations.

We have limited control over the activities on properties that we do not operate.

Other companies operate some of the properties in which we have an interest. As of December 31, 2018 , our operated wells accounted for approximately 60% of our total estimated proved reserves and wells operated by others accounted for the remaining 40% of our total estimated proved reserves. We have limited ability to influence or control the operation or future development of these non-operated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. In the past, we have changed our development plans for certain proved undeveloped reserves and expect future development plans may also change as the operators of our outside operated properties adjust their capital plans based on prevailing market conditions. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

This Annual Report contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. Oil and natural gas reservoir engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, drilling and operating expenses, capital expenditures, development costs and workover and remedial costs, the assumed regulations by governmental agencies, the quantity, quality and interpretation of relevant data, taxes and availability of funds.

 

As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. We prepare our own estimates of proved reserves and engage Miller and Lents, an independent petroleum engineering firm, to audit 100% of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, the calculation of estimated reserves requires certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs, any of which assumptions may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.

This year, because substantial doubt exists about our ability to continue as a going concern, we can no longer support our proved undeveloped reserves due to uncertainty that we have the ability to fund a development plan. Therefore, as of December 31, 2018, we reclassified all of our proved undeveloped reserves to contingent resources. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve data assumes that we can and will make these significant expenditures to develop our reserves and conduct these drilling operations successfully. These assumptions, however, may not prove correct, and our estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.

For example, to illustrate the impact of a volatile oil, natural gas and NGLs price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining oil, natural gas and NGLs prices and declining production), our total proved reserves as of December 31, 2018 would decrease from 1,077.5 Bcfe to 921.9 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.83 per MMBtu (or a $0.27 price decrease from the 12-month average price of $3.10) and oil prices were $55.94 per barrel (or a $9.72 price decrease from the 12-month average price of $65.66), while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2018 would decrease from 1,077.5 Bcfe to 1,020.8 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year NYMEX forward strip price at April 8, 2019 . Our PV-10 is calculated using prices based on the 12-month average price, as defined by the SEC, and does not give effect to derivative transactions. Numerous changes over time to the assumptions on which our reserve estimates are

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based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

Actual future net cash flows from our oil, natural gas and NGLs properties also will be affected by factors such as:

•	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.

In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future net cash flows, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

The PV-10 of our proved reserves at December 31, 2018 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.

You should not assume that the present value of future net reserves (“PV-10”) value of our proved reserves as of December 31, 2018 is the current market value of our estimated oil, natural gas and NGLs reserves. In accordance with SEC standards, we base the discounted future net cash flows from our proved reserves on the 12-month average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

•	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 timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided herein. In addition, the 10% discount factor that is required by the SEC to be used when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report, which could have a material effect on the value of our reserves. The oil and natural gas prices used in computing our PV-10 and standardized measure of future cash flows as of December 31, 2018 under SEC guidelines were $65.66 per barrel of crude oil and $3.10 per MMBtu for natural gas, respectively, before price differentials.

Using more recent prices in estimating proved reserves would result in a reduction in proved reserve volumes because they are lower than the prices used in estimated proved reserves and due to economic limits, which would further reduce the PV-10 value of our proved reserves. Any adjustments to the estimates of proved reserves or decreases in the price of our oil, natural gas and NGLs may decrease the value of our securities.

Our operations require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to sustain our operations at current levels and could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We have made and, subject to the approval of the Bankruptcy Court, ultimately expect to continue to make substantial capital expenditures in our business for the development, production and

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acquisition of oil, natural gas and NGLs reserves. We intend to finance our future capital expenditures with cash flow from operations, our financing arrangements and asset sales. Our cash flow from operations and our access to capital are subject to a number of variables, including, but not limited to:

•	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.

If our revenues decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to replace or add to our reserves. Additionally, due to the 2019 Chapter 11 Cases, our access to capital raising and financing opportunities will be limited, if it is available at all. If additional capital is needed, we may not be able to obtain financing on terms favorable to us, or at all, as discussed elsewhere in Part I, Item 1A “Risk Factors.” If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and NGLs we produce and could reduce our revenues.

The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties as well as gathering systems, gas processing facilities and downstream refineries in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system or lack of contracted capacity on such systems. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells, the reduction in wellhead pricing or the delay or discontinuance of development plans for properties. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues. Federal, state and local regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather, process, refine and market our oil, natural gas and NGLs.

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We may incur losses as a result of title defects in the properties in which we invest.

We purchase working and revenue interests in the oil and natural gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the interest under the property. The cost of performing detailed title work can be expensive. We may choose to forgo detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. As is customary in our industry, we generally rely upon the judgment of oil and gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and gas leases can be generally lost and the target area can become undrillable.

We depend on certain key customers for sales of our oil, natural gas and NGLs. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs they purchase from us, or to the extent these customers cease to be creditworthy, our revenues and cash flows from operations could decline.

We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2018 , sales of oil, natural gas and NGLs to Mieco Inc. , Exxon , Plains Marketing, L.P. , Macquarie Energy and ConocoPhillips accounted for approximately 14% , 7% , 6% , 6% and 5% , respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2018 therefore accounted for 38% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, or fail to pay us, our revenues and cash flows from operations could decline.

We are, and may be from time to time, subject to litigation, which could have an adverse effect on our financial condition, results of operations, and cash flow.

We are a party to various claims and routine litigation arising in the ordinary course of business. Such litigation is inherently uncertain, and results cannot be predicted. Regardless of the outcome, such claims or litigations could have an adverse impact on us because of diversion of management and other personnel and other factors. Some of these claims, to which we may be subject from time to time, may result in defense costs, settlements, fines or judgments against us, some of which are not, or cannot be, covered by insurance. Payment of any such costs, settlements, fines or judgments that are not insured could have an adverse impact on our financial position, results of operations or cash flow. In addition, it is possible that a resolution of one or more such claims could result in judgments, consent decrees or orders requiring a change in our business practices, which could have an adverse impact on our financial position, results of operations or cash flow.

Our sales of oil, natural gas and NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The FTC, FERC and CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas and NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

We are subject to FERC requirements related to our use of capacity on natural gas pipelines that are subject to FERC regulation. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

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The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.

Laws and regulations pertaining to threatened and endangered species could delay or restrict our operations and cause us to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, CERCLA, the OPA and the Clean Water Act.

If endangered or threatened species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, the government could seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA.

Please read “Operations-Environmental and Occupational Health Safety Matters-Endangered Species Act Considerations” included under Part I, Item 1 of this Annual Report.

We are subject to compliance with environmental and occupational safety and health laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent and complex federal, state and local laws and regulations with respect to environmental protection, and the health and safety of employees. These laws and regulations may impose numerous obligations on our operations such as: the acquisition of permits, including drilling permits, to conduct regulated activities; the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmental sensitive areas such as wetlands, wilderness regions and other protected areas; the imposition of substantial liabilities for pollution resulting from our operations; and the application of specific health and safety criteria addressing worker protection. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations, financial condition or cash flows. We may be required to make large expenditures to comply with environmental and other governmental regulations. We maintain insurance common to the industry related to pollution resulting from operations. As mentioned below, prior operators releases may be unknown to us.

Failure to comply with these laws and regulations can result in suspension or termination of operations, civil and criminal fines and penalties, the imposition of investigatory, corrective action or remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose joint and several strict liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We may incur significant environmental costs and liabilities to the government or third parties in the performance of our operations as a result of our handling petroleum hydrocarbons, hazardous substances and wastes, because of air emissions and wastewater discharges relating to our operations, and due to historical industry operations and waste disposal practices by us or prior operators or other third parties over whom we had no control. For example, an accidental release of petroleum

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hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Laws and regulations protecting the environment have become more stringent in recent years and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. The possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please read “Operations-Environmental and Occupational Health Safety Matters” included under Part I, Item 1 of this Annual Report.

Climate change legislation and regulatory initiatives restricting emissions of GHGs or legal or other action taken by public or private entities related to climate change may adversely affect our operations, our cost structure, or the demand for oil and natural gas.

The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.

U.S. EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. Please read “Operations-Environmental and Occupational Health Safety Matters-Climate Change” included under Part I, Item 1 of this Annual Report. These U.S. EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities, should those facilities exceed threshold permitting levels of GHG emissions.

A number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

It should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Water is an essential component of both the drilling and hydraulic fracturing processes. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

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While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, i ncreased federal interest has arisen in recent years. Please read “Operations-Environmental and Occupational Health Safety Matters-Hydraulic Fracturing” included under Part I, Item 1 of this Annual Report. Some states in which we operate, including Montana, Texas and Wyoming, have adopted and other states have considered adopting legal requirements that could impose more stringent permitting public disclosure, or well construction requirements on hydraulic fracturing activities. Other states, such as Oklahoma, have imposed restrictions on injection of produced wastewater due to induced seismicity concerns or, such as New York, prohibit hydraulic fracturing altogether. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of produced water. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Policy changes initiated during the first year of the new Presidential Administration could result in an increase in the overall fuel supply, lessening the demand or price for the Company’s output.

The current Presidential Administration has made several policy and rule changes intended to reinvigorate coal’s use for energy production and increase the total available petroleum supply.

The new Administration has taken steps to reverse policies of the prior Administration that disadvantaged coal as a fuel for energy production. On February 16, 2017, the new Administration repealed the Stream Protection Rule, which limited mountaintop mining. In March 2017, the Interior Department lifted the prior Administration’s ban on new coal leasing on federal land. In December 2018, the U.S. EPA proposed limitations to the mercury air emission limits set in the 2012 mercury and air toxic standards. In June 2017, the United States withdrew from the Paris Agreement, pursuant to which the country had pledged reductions in greenhouse gas emissions. In July 2017, the U.S. EPA issued a proposed rule rescinding the Clean Water Rule that had been issued in June 2015, which sought to designate what water bodies are subject to the Clean Water Act’s protection and was seen as a constraint on coal mining operations. The U.S. EPA is in the administrative process of preparing a replacement rule. In August 2018, U.S. EPA proposed a rule to replace the Clean Power Plan that had been in place to regulate carbon emissions.

The new Administration has reversed several policies of the prior Administration that restricted, or imposed additional costs on, petroleum extraction or processing. In March 2017, the new U.S. EPA issued a federal permit for the Keystone XL pipeline, eventually allowing processing of Alberta oil sands at refineries in the Gulf Coast. In March 2017, the new Administration issued Executive Order 13783 promoting the development of energy resources and directing agency heads to review existing regulations affecting, among other things, petroleum extraction. In June 2017, U.S. EPA proposed staying the 2016 Methane Rule, which imposed operating practices to limit emissions from fracturing operations and required “green completions” of fractured wells. In October 2018, the U.S. EPA issued a proposed rule that would reconsider limits on methane emissions set by the Methane Rule and reduce inspection and repair requirements. In September 2018, the Interior Department rescinded the prior Administration’s rule restricting flaring methane from production wells on federal lands. In May 2018, the Interior Department proposed changes in 2016 safety rules governing offshore oil and gas production (e.g., third-party certification of safety devices, safety system design requirements and failure reporting). On December 29, 2017, the new Administration rescinded rules imposing well-integrity testing, chemical use reporting, and waste fluids storage requirements on production wells on federal lands. On January 4, 2018, the Administration announced it would lift the prior Administration’s moratorium to allow new offshore oil and gas drilling in nearly all U.S. coastal waters, including off California for the first time in decades, and hold 47 lease sales over the coming years. Several of these actions are subject to pending legal challenge by states and environmental groups.

If they withstand whatever court challenges they might confront to become effective, and, in the case of the coal initiatives, have the effect of increasing coal’s use for energy production, these initiatives could have the effect of increasing the overall fuel supply, thereby reducing the demand for, or price of, the Company’s output.

The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of oil, natural gas and NGLs prices, interest rate and other risks associated with our business.

On July 21, 2010 comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives

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market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the legislation. While some of these rules have been finalized, some have not been finalized or implemented, and it is not possible at this time to predict when this will be accomplished. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions for bona fide hedging transactions. However, these rules have not been finalized, and their impact on our hedging activities is uncertain.

The Act and the CFTC rules require derivatives market participants to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements) in connection with certain interest rate swap and credit default swap activities, and certain of our derivatives activities are subject to such requirements. In addition, the CFTC and the prudential banking regulators each published final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants or financial end users.

While we do not anticipate being subject to clearing, trade-execution or margin requirements, the application of these requirements to other market participants could affect the cost and availability of swaps we use for hedging. Other rules remain to be finalized by the CFTC and the SEC, and certain compliance dates have yet to come into effect. As a result it is not possible at this time to predict with certainty the full effects of the Act and the rules promulgated thereunder on us or the timing of such effects. The Act and any new rules promulgated thereunder could increase the cost of derivative contracts (including from requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, impact oil, natural gas and NGLs prices and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Act or the rules promulgated thereunder, our results of operations may become more volatile and our cash flows may be less predictable. Any of these consequences could have material, adverse effect on us, our financial condition, and our results of operations. In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.

Counterparty failure may adversely affect our derivative positions.

We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our net cash provided by operating activities, financial condition and results of operations would be adversely affected.

Increased IT security threats and more sophisticated and targeted computer crime could pose a risk to our systems, networks, products, facilities and services.

The oil and natural gas industry is increasingly dependent on digital technologies to conduct certain exploration, development and production activities. Software programs are used for, among other things, reserve estimates, seismic interpretation, modeling and compliance reporting. In addition, the use of mobile communication is widespread. Increased information security threats and more sophisticated, and coordinated and targeted computer crime pose a risk to the confidentiality, availability and integrity of our data, operations and infrastructure. In addition, the Company maintains interfaces with certain third-party service providers. Threats to information security also exist in the processing of customer information through various other vendors and their personnel. While we attempt to mitigate these risks by employing a number of measures, including security measures, employee training, comprehensive monitoring of our networks and systems, and maintenance of backup and protective systems, our employees, systems, networks, products, facilities and services remain potentially vulnerable to sophisticated espionage or cyber-assault. Depending on their nature and scope, if our systems for protecting against cyber incidents prove insufficient, such threats could potentially lead to the compromise of confidential information, improper use of our systems and networks, manipulation and destruction of data, defective products, production downtimes and operational disruptions, which in turn could adversely affect our reputation, competitiveness and results of operations. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities.

A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including, but not limited to, the following:

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•	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.

Additionally, certain cyber incidents may remain undetected for an extended period. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows. Furthermore, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

Locations that we or the operators of our properties decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we or the operators of our properties drill dry holes or wells that are productive but do not produce enough oil, natural gas or NGLs to be commercially viable after drilling, operating and other costs. If we or the operators of our properties drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

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Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash flows from operations.

Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGLs prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing leasehold acreage. As of December 31, 2018 , we have identified 3,083 (gross) drilling locations. These identified drilling locations represent a significant part of our strategy. The SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. Therefore, due to uncertainty that we have the ability to fund a development plan, as of December 31, 2018, we reclassified all of our proved undeveloped reserves to contingent resources because substantial doubt exists about our ability to continue as a going concern, and we no longer expect to develop our proved undeveloped reserves within five years of initial booking.

Our ability to drill and develop these locations depends on a number of factors, including, among others, the availability of capital, seasonal conditions, regulatory approvals, and economic and industry conditions at the time of drilling, including prevailing and anticipated oil, natural gas and NGLs prices and the availability and prices of drilling rigs and crews, fracturing crews and related equipment and material. As we have not assigned any proved reserves to the drilling locations we have identified and scheduled for drilling, there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected time frame or will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial position and results of operations.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business activities, financial condition or results of operations.

Our future business activities, financial condition and results of operations depend on the success of our exploration and production activities. Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil, natural gas or NGLs can be substantial, uncertain and uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including, but not limited to:

•	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;

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•	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.

In addition, a portion of our natural gas production is processed to extract NGLs at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut-in our natural gas production, or the alternative facilities could be more expensive than the facilities we currently use.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, clean up responsibilities, loss of well location, acreage, expected production and related reserves, and regulatory investigations and penalties. Also, any delay in the drilling program or significant increase in costs could adversely affect business activities, financial condition and results of operations.

In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses. If we experience any problems with well stimulation and completion activities, such as hydraulic fracturing, our ability to explore for and produce oil or natural gas may be adversely affected.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or

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uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Seasonal weather conditions, severe weather events, and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Seasonal weather conditions, severe weather events, and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increased costs or delay our operations. Generally, but not always, oil is typically in higher demand in the late summer due to the summer driving season, which results in increased gasoline and diesel usage and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as hot summers or mild winters sometimes impact this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers, joint interest owners and by counterparties to our price risk management arrangements. Some of our vendors, customers, joint interest owners and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers, joint interest owners and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’, joint interest owners’ and counterparties’ liquidity and ability to make payments or perform on their obligations to us.  Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers, joint interest owners and/or counterparties could reduce our revenues.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend on senior management personnel, each of whom would be difficult to replace.

We depend on the performance of R. Scott Sloan, our President and Chief Executive Officer, Ryan Midgett, our Chief Financial Officer, and Jonathan Curth, our General Counsel, Corporate Secretary and Vice President of Land. We do not maintain key person insurance for either of Messrs. Sloan, Midgett or Curth. The loss of any of Messrs. Sloan, Midgett or Curth could negatively impact our ability to execute our strategy and our results of operations.

We may be unable to compete effectively with larger companies in the oil and natural gas industry.

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The oil and natural gas industry is intensely competitive in acquiring properties, marketing oil and natural gas and securing trained personnel, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and NGLs but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may have greater and more productive assets, greater access to capital, substantially larger staffs and greater financial and operating resources and may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGLs prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Due to our small size, poor results in any single exploration, development or production play can have a disproportionately negative impact on us. We also compete for people, including experienced geologists, geophysicists, engineers and other professionals. Our limited size has placed us at a disadvantage with respect to attracting and retaining management and other professionals with the technical abilities necessary to successfully operate our business. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with our larger competitors that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. In addition, competition is strong for attractive oil, natural gas and NGLs producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Federal securities laws could limit our ability to book additional proved undeveloped reserves in the future.

Under the federal securities laws, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. This year, because substantial doubt exists about our ability to continue as a going concern, we no longer expect to develop our proved undeveloped reserves within five years of initial booking due to uncertainty that we have the ability to fund a development plan. Therefore, as of December 31, 2018, we reclassified all of our proved undeveloped reserves to contingent resources.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation .

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the recent tax legislation commonly referred to as the Tax Cuts and Jobs Act of 2017 (the “Tax Act”), which was signed on December 22, 2017, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on our financial position, results of operations and cash flows.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential investors could lose confidence in our financial reporting, which would harm our business and the trading price of our securities.

Internal control over financial reporting is a process designed 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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may

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become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations.

Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our securities.

Multi-well pad drilling and project development may result in volatility in our operating results.

We utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.

Access to water to drill and conduct hydraulic fracturing may not be available if water sources become scarce, and we may face difficulty disposing of produced water gathered from drilling and production activities.

The availability of water is crucial to conduct hydraulic fracturing. A significant amount of water is necessary for drilling and completing each well with hydraulic fracturing. In the past, Texas has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. Although we have taken measures to secure our water supply, we can make no assurances that sufficient water resources will be available in the short or long term to carry out our current activities. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

We may not be able to keep pace with technological developments in our industry.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be adversely affected.

Our business and the trading prices of our securities could be negatively affected as a result of actions of so-called “activist” shareholders, and such activism could impact the trading value of our securities.

Stockholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. If we become the subject of activity by activist shareholders, responding to such actions could be costly and time-consuming, diverting the attention of our management and employees. Furthermore, activist campaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities and cause the price of our Common Stock to experience periods of volatility.

Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

Our ability to utilize U.S. net operating loss, or NOL, carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended, or the Code. As disclosed in Note 13 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” we have substantial NOL

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carryforwards. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our Common Stock by 5 percent stockholders and the offering of our Common Stock during any three-year period resulting in an aggregate change of more than 50 percent in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. As of December 31, 2018, we do not believe that an ownership change has occurred; however, to the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitations were not in effect. In addition, U.S. NOLs generated on or after January 1, 2018, can be limited to 80 percent of taxable income. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect our ability to refinance our indebtedness.

Financial regulators are working to transition away from the London Interbank Offered Rate (“LIBOR”) as a reference rate for financial contracts. On July 27, 2017, the Financial Conduct Authority announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. While our Successor Credit Facility is scheduled to mature in the first half of 2021, potential changes, or uncertainty related to such potential changes, in interest rate benchmarks may adversely affect our ability to refinance our indebtedness. There is no guarantee that a transition from LIBOR to an alternative will not result in financial market disruptions, significant increases in benchmark rates or borrowing costs to borrowers, any of which could have an adverse effect on our business, financial condition and results of operations.

Risks Related to Our Common Stock

The price of our Common Stock has declined substantially since January 1, 2018 and is likely to remain depressed throughout the pendency of our bankruptcy proceedings.

The trading price of our Common Stock has declined substantially since January 1, 2018 from a high of $20.50 in January 2018 to a low of $0.03 at April 8, 2019 . The price of our Common Stock is likely to remain depressed in response to market and other factors some of which are beyond our control, including:

•	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;

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•	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.

Broad market and industry factors may decrease the market price of our Common Stock, regardless of our actual operating performance. The stock market in general has from time to time experienced extreme price and volume fluctuations, including periods of sharp decline. In the past, following periods of volatility in the overall market and the market price of a company’s securities, securities class action litigation has often been instituted against these companies. Such litigation, if instituted against us, could result in substantial costs and be a diversion of our management’s attention and resources.

No assurance can be given that an active market will develop for our Common Stock or as to the liquidity of the trading market for our Common Stock. Our Common Stock may be traded only infrequently, and reliable market quotations may not be available. Holders of our Common Stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, sales of our Common Stock by existing stockholders, or the perception that these sales may occur, especially by directors or significant stockholders of the Company, may cause our stock price to decline.

Our Common Stock is quoted on the OTC Pink and is held by a small group of investors.

As of April 2, 2019, our Common Stock is quoted on the OTC Pink under the symbol “VNRRQ” after the OTC Market Group Inc. downgraded our Common Stock and warrants from the OTCQX U.S. tier. The OTC Pink is a more limited market than the OTCQX U.S. tier, and the quotation of our Common Stock on the OTC Pink may result in a less liquid market available for existing and potential stockholders to trade our Common Stock and could further depress the trading price of our Common Stock. There can be no assurance that any public market for our Common Stock will exist in the future or that the Company or its successor will be able to participate again in the OTCQX U.S. tier. In connection with the downgrade to the OTC Pink, there also may be other negative implications, including the potential loss of confidence in us by suppliers, customers and employees, fewer business development opportunities, a limited amount of news and analyst coverage for our Company, a decreased ability to issue additional securities or obtain additional financing in the future and the loss of institutional investor interest in our Common Stock.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with Marathon Asset Management, L.P. (“Marathon”), Contrarian Capital Management, L.L.C. (“Contrarian”), Monarch Alternative Capital LP (“Monarch”), Silver Point Capital, L.P. and FMR LLC collectively owned approximately 64.2% of our outstanding Common Stock as of April 8, 2019 . Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, if such action, in their judgment, could enhance their investment in the Company. Such transactions might adversely affect us or other holders of our Common Stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our Common Stock because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our Common Stock in the public market or the issuance of securities senior to our Common Stock, or the perception that these sales may occur, could adversely affect the trading price of our Common Stock and our ability to raise funds in stock offerings.

A large percentage of our shares of Common Stock is held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we filed a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our Common Stock in the public markets, or even the perception that these sales might occur (such as pursuant to the aforementioned registration statement), could cause the market price of our Common Stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities. Given the limited trading

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volume, we cannot predict the effect that future sales of our Common Stock or other equity-related securities would have on the market price of our Common Stock.

We do not expect to pay dividends in the near future.

We do not intend to pay cash dividends on our Common Stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Any payment of future dividends will be at the discretion of the Board and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions and other considerations that the Board deems relevant. In addition, any future dividend payments will be restricted by the terms of the agreements governing our indebtedness. Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our Common Stock.

Certain provisions of our Certificate of Incorporation and our Bylaws may make it difficult for stockholders to change the composition of the Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Amended and Restated Certificate of Incorporation (“Certificate of Incorporation”) and our Amended and Restated Bylaws (“Bylaws”) may have the effect of delaying or preventing changes in control if the Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:

•	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.

These provisions could enable the Board to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of the Board, which is responsible for appointing the members of our management.

We are a “smaller reporting company” and, as such, are allowed to provide less disclosure than larger public companies.

We are currently a “smaller reporting company,” as defined by Rule 12b-2 of the Exchange Act. As a “smaller reporting company,” we have certain decreased disclosure obligations in our SEC filings, which may make it harder for investors to analyze our results of operations and financial prospects and may result in less investor confidence.

ITEM 1B.     UNRESOLVED STAFF COMMENTS

 

None.

 

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ITEM 2.     PROPERTIES

 

A description of our oil and natural gas properties is included in Part I, Item 1 of this Annual Report, and is incorporated herein by reference.

We have office leases in Houston and Odessa, Texas; Gillette, Wyoming; and McAlester, Oklahoma. As of December 31, 2018 , the lease for the Houston office covers approximately 42,940 square feet of office space with a term ending on June 30, 2026. Our lease for the Odessa office covers approximately 6,700 square feet of office space, and runs through June 30, 2019. In Wyoming, the lease for our Gillette office covers approximately 5,000 square feet with a lease term expiring on April 30, 2019. We are also leasing a fenced yard in Gillette, Wyoming with lease term ending on April 1, 2019. Our lease for the McAlester, Oklahoma office covers approximately 1,500 square feet with a lease term ending on July 31, 2020. We also lease a storage space adjacent to the McAlester, Oklahoma office with lease term ending concurrently with the office lease. We also have leases in Eunice and Artesia, New Mexico and Mustang, Oklahoma which are month-to-month. The total annual cost of our office leases for 2018 was approximately $2.2 million.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

 

ITEM 3.     LEGAL PROCEEDINGS

Please see “Item 1 - Business - Bankruptcy Proceedings under Chapter 11” for information regarding our 2019 Chapter 11 Cases.

Please read “Emergence from Voluntary Reorganization under 2017 Chapter 11 Proceedings” included under Part I, Item 1 of this Annual Report for information regarding our 2017 Chapter 11 Cases.

We are also a party to separate legal proceedings as further discussed below.

Litigation Relating to Vanguard’s 2015 merger with LRR Energy, L.P.

In June and July 2015, purported unitholders of LRR Energy, L.P. (“LRE”) filed four lawsuits challenging Vanguard’s 2015 merger with LRE (the “LRE Merger”). These lawsuits were styled (a) Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware; (b) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; (c) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District; and (d) Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division. These lawsuits have been voluntarily dismissed or nonsuited.

On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit in connection with the LRE Merger. This lawsuit is styled Robert Hurwitz v. Eric Mullins et al., Civil Action No. 1:15-cv-00711-MAK, in the United States District Court for the District of Delaware (the “LRE Lawsuit”). On June 22, 2016, the LRE Plaintiff filed his Amended Class Action Complaint (the “Amended LRE Complaint”) against LRE, the members of the board of directors of the general partner of LRE, Vanguard, Lighthouse Merger Sub, LLC, and the members of the Board (the “LRE Lawsuit Defendants”).

In the Amended LRE Complaint, the LRE Plaintiff alleges multiple causes of action under the Securities Act and Exchange Act related to the registration statement and proxy statement filed with the SEC in connection with the LRE Merger (the “LRE Proxy”). In general, the LRE Plaintiff alleges that the LRE Proxy failed, among other things, to disclose allegedly material details concerning Vanguard’s (x) debt obligations and (y) ability to maintain distributions to unitholders. Based on these allegations, the LRE Plaintiff sought, among other relief, to rescind the LRE Merger, and an award of damages, attorneys’ fees, and costs.

On January 2, 2018, the court in the LRE Lawsuit certified a class of plaintiffs that includes all persons or entities holding LRE common units as of August 28, 2015, through the close of the LRE Merger on October 5, 2015, but excluding the LRE Lawsuit Defendants and certain related persons and entities (the “LRE Class”). The window for potential members of the LRE Class to request exclusion from the LRE Class closed on May 29, 2018, with 22 LRE unitholders timely requesting exclusion.

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On June 27, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff, on his own behalf and on behalf of the LRE Class, entered into a stipulation of settlement (the “Stipulation”). As amended on July 11, 2018, and on July 25, 2018, the Stipulation provided that the LRE Class settle and release all claims against the LRE Lawsuit Defendants relating to the LRE Merger, in exchange for an aggregate settlement payment of $8.0 million. Of that settlement amount, Vanguard was to contribute $0.7 million, with the remainder to be paid by the insurers of the LRE Lawsuit Defendants. The LRE Lawsuit Defendants continue to deny all allegations of liability or wrongdoing.

On July 18, 2018, the court held a hearing to consider whether to preliminarily approve the proposed settlement. In response to matters raised at that hearing, on July 25, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff amended the Stipulation and submitted to the court a revised notice of proposed settlement, proof of claim and release form, and summary notice of proposed settlement. On July 26, 2018, the court entered an order preliminarily approving the settlement as set forth in the amended Stipulation.

On December 14, 2018, the court held a hearing to consider whether to finally approve the proposed settlement. Also on December 14, 2018, the court entered an order finally approving the settlement and finding that “the settlement with its two levels of consideration is fair, reasonable, and adequate to all members of the Class of Plaintiffs.” On December 19, 2018, the parties filed a Joint Motion to Amend the Judgment, asking the court to amend, in certain respects, the order finally approving the settlement. Later that day, the court granted the parties’ Joint Motion to Amend the Judgment and entered an Amended Judgment Order that clarifies, in certain respects, its initial order finally approving the settlement and instructs the clerk of court to close the case.

The case is now closed.

We are also defendants in certain legal proceedings arising in the normal course of our business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on the Company cannot be predicted with certainty. Furthermore, our insurance may not be adequate to cover all liabilities that may arise out of claims brought against us. If one or more negative outcomes were to occur relative to these matters, the aggregate impact to our financial position, results of operations or cash flow could be material.

In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under applicable environmental laws, that could reasonably be expected to have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow. 

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

       

As of April 2, 2019, our Common Stock is quoted on the OTC Pink under the symbol “VNRRQ.” Prior to April 2, 2019, our Common Stock was traded on the OTCQX U.S. tier of the OTC Markets since September 28, 2017. No established public trading market existed for our Common Stock prior to September 28, 2017. On April 8, 2019 , there were 20,124,080 outstanding shares of common stock and approximately eighteen stockholders, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank.

Our Predecessor’s common units commenced quotation on the OTC Pink on February 13, 2017 under the symbols VNRSQ, VNRAQ, VNGBQ and VNRCQ, respectively

  

Prior to the commencement of the 2017 Chapter 11 Cases, our Predecessor’s common units were traded on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group, Inc. under the symbol “VNR”.

  

Equity Compensation Plans.  Please read “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans as of December 31, 2018 . 

ITEM 6.   SELECTED FINANCIAL DATA

 

As a Smaller Reporting Company, we are not required to provide the selected financial data information required by this Item, but we have provided below our summary reserve and operating data.

Summary Reserve and Operating Data

 

The following tables show estimated net proved reserves based on a reserve report prepared by us and audited by independent petroleum engineers, Miller and Lents, and certain summary unaudited information with respect to our production and sales of oil, natural gas and NGLs. You should refer to Risk Factors under Part I, Item 1A and Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this Annual Report and, “Oil, Natural Gas and NGLs Data—Estimated Proved Reserves” and “Oil, Natural Gas and NGLs Data—Production and Price History” included under Part I, Item I of this Annual Report when evaluating the material presented below.

 

	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

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(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 .

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated. Information for fields with greater than 15% of our total proved reserves have been listed separately in the table below for the years ended December 31, 2018 , 2017 , and 2016 .

		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

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properties and related assets. The production of these properties are included from the closing date of the acquisition forward.

(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).

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS

You should read the following discussion and analysis in conjunction with Part II, Item 6 of this Annual Report and the accompanying financial statements and related notes included elsewhere in this Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in Part I, Item 1A of this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

As discussed in Notes 2, 14 and 15 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, the Company applied fresh-start accounting upon emergence from bankruptcy on August 1, 2017, using a convenience date of July 31, 2017, at which time it became a new entity for financial reporting purposes. The effects of the Plan of Reorganization (described below) and the application of fresh-start accounting were reflected in our consolidated financial statements as of July 31, 2017 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period February 1, 2017 to July 31, 2017 (predecessor). References to the Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date.

We adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the fair value of our total assets or the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Final Plan, our consolidated financial statements subsequent to July 31, 2017 are not comparable to our consolidated financial statements prior to July 31, 2017, and as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

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Overview

 

We are an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States. Through our operating subsidiaries, as of December 31, 2018 , we own properties and oil and natural gas reserves primarily located in nine operating basins:

•	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.

At December 31, 2018 , we owned working interests in 10,330 gross ( 3,620 net) productive wells. Our operated wells accounted for approximately 60% of our total estimated proved reserves at December 31, 2018 . Our average net daily production was 346,128 Mcfe/day for the year ended December 31, 2018 and was 324,478 Mcfe/day for the fourth quarter of 2018 . Our total estimated proved reserves at December 31, 2018 were 1,077.5 Bcfe, of which approximately 19% were oil reserves, 64% were natural gas reserves and 17% were NGLs reserves. Of these total estimated proved reserves, approximately  100%  were classified as proved developed.

Recent Developments and Outlook

Bankruptcy Proceedings under Chapter 11

 

2019 Chapter 11 Proceedings

 

On March 31, 2019, the 2019 Debtors filed voluntary petitions for relief under Chapter 11 of the 2019 Bankruptcy Code in the Bankruptcy Court. During the pendency of the bankruptcy proceedings, we will continue to operate our business as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

Debtor-in-Possession Financing

In connection with the 2019 Chapter 11 Cases, on the 2019 Petition Date, the 2019 Debtors filed the DIP Motion seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in the DIP Credit Agreement among the DIP Borrower, the financial institutions or other entities from time to time parties thereto, as lenders, the DIP Agent and as issuing bank. The initial lender under the DIP Credit Agreement is Citibank N.A.

The DIP Credit Agreement is subject to final approval of the Bankruptcy Court, which has not been obtained at this time. We can provide no assurances that the DIP Motion will be granted.

Automatic Stay

 

Subject to certain specific exceptions under the Bankruptcy Code, the 2019 Bankruptcy Petitions automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims.

 

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Executory Contracts

 

Subject to certain exceptions, under the Bankruptcy Code, the 2019 Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the 2019 Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach.

 

Chapter 11 Filing Impact on Creditors and Stockholders

 

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. The outcome of the 2019 Chapter 11 Cases remain uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors and stockholders may receive. It is possible that stockholders will receive no distribution on account of their interests. Please read Part I, Item 1, Business for further discussion on plan provisions.

 

Reorganization Expenses

 

The 2019 Debtors have incurred and will continue to incur significant costs associated with the reorganization, principally professional fees. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations.

 

Risks Associated with 2019 Chapter 11 Cases

 

For the duration of our 2019 Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this Form 10-K may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Going Concern Assessment

As discussed below under “Capital Resources and Liquidity”, we have concluded that there is substantial doubt about our ability to continue as a going concern and the report of the independent registered public accounting firm that accompanies the audited consolidated financial statements for the year ended December 31, 2018 included in this Annual Report on Form 10-K contains an explanatory paragraph regarding substantial doubt about our ability to continue as a going concern due to the filing of the 2019 Chapter 11 Cases.

Asset Sales

During 2018, the Company completed the sale of certain oil and natural gas properties in the Permian Basin, the Green River Basin, Arkoma Basin and in Mississippi. The Company also sold its working interests in related oil and natural gas producing properties located in multiple counties in Texas, Louisiana and Colorado. Additionally, as discussed in Note 2, the Company completed the Potato Hills Divestment on August 1, 2018. Net cash proceeds received from the sale of all of these properties were approximately $102.2 million, subject to customary post-closing adjustments. Additionally, we incurred costs to sell of approximately $3.0 million. These dispositions were treated as asset sales, and resulted in a net gain of approximately $4.7 million, which is included in “net gain (loss) on divestiture of oil and natural gas properties” on the condensed consolidated statement of operations. The net cash proceeds from these divestments were used to pay down outstanding debt under the Successor Credit Facility (defined in Note 6).

Capital Development

The Board approved, subject to the approval of the DIP Agent and the agent under the Successor Credit Facility, a capital expenditures budget for 2019, of approximately $53.0 million compared to the $124.9 million we spent in 2018 . Our 2019 capital expenditures budget includes approximately $24.0 million of drilling and completion capital focused on the core growth assets of the Green River and Arkoma Basins. If our 2019 capital expenditures budget is approved by the DIP Agent and the agent under the Successor Credit Facility, we expect to spend approximately $15.0 million of the drilling capital budget in the Arkoma Basin where we will participate as a non-operated partner in the drilling and completion of horizontal wells targeting the Woodford and

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Mayes formations. This program is a continuation of our 2018 one rig program with Newfield Exploration Company, (“Newfield”). The acquisition of Newfield by Encana Corporation has delayed the completion of the program. However, we anticipate further evaluation of the scope and timing of this project to recommence later this fiscal year. Furthermore, we expect to spend approximately $9.0 million in the Green River Basin at the Pinedale field where we participate as a non-operated partner in the drilling of vertical natural gas wells with Ultra Petroleum Corporation and Pinedale Energy Partners. In addition to our drilling and completion programs, we expect to spend approximately $8.0 million on other uplift projects, primarily in the Permian New Mexico Red Lake field, where we will expand on our successful 2018 operated Yeso recompletion and commingle program. The remaining $21.0 million of the capital program will be spent on maintenance and land projects that include safety and environmental compliance, compressor overhauls, facility work, returning wells to production that go offline during the year and other capital required to maintain reserves and operations.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. The WTI crude oil spot price per barrel during the years ended December 31, 2017 and 2018 ranged from a low of $42.48 to a high of $77.41 and the Henry Hub natural gas spot price per MMBtu during the same period ranged from a low of $2.44 to a high of $6.24 . NGLs prices were similarly volatile. As of April 8, 2019 , the WTI crude oil spot price per barrel was $61.59 and the Henry Hub natural gas spot price per MMBtu was $2.73 . Among the factors causing such volatility are the domestic and foreign supply of oil and natural gas, the ability of the OPEC members to comply with the agreed upon production cuts and the cooperation of other producing countries to reduce production levels, social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States and the level and growth of consumer product demand.

To illustrate the impact of a volatile oil, natural gas and NGLs price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining oil, natural gas and NGLs prices and declining production), our total proved reserves as of December 31, 2018 would decrease from 1,077.5 Bcfe to 921.9 Bcfe and PV-10 would decrease from $1.2 billion to $0.7 billion, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices and oil prices were derived from the 5-year NYMEX forward strip price (using monthly NYMEX settlement prices through December 2024) at April 8, 2019 , our total proved reserves as of December 31, 2018 would decrease from 1,077.5 Bcfe to 1,020.8 Bcfe and PV-10 would decrease from $1.2 billion to $ 0.9 billion . Below is a tabular presentation of the prices depicted in illustration (2) which differ from the SEC 12-month average pricing of $3.10 per MMBtu for natural gas and $65.66 per barrel of crude oil (held constant):

	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

(1) Prices for 2024 and subsequent years were not escalated and were held flat for the remaining lives of the properties. Capital and lease operating expenses were also not inflated and held constant for the remaining lives of the properties.

When comparing these settlement prices to the prices of $3.10 per MMBtu for natural gas and $65.66 per barrel of crude oil used to generate our December 31, 2018 (“4Q18”) reserve report, the average annual prices for oil, the price for each annual year presented above is slightly higher than the 4Q18 reserve report price, however the price for natural gas decreased slightly. The impact of the relative consistency in forward prices to gas wells and oil wells, when compared to the 4Q18 reserve report prices, includes stability in projected economic lives and economically recoverable volumes, despite the minor movement in prices. The following table compares the 4Q18 reserve report volumes by product with the strip pricing volumes:

	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)%

Management believes that the use of the 5-year NYMEX forward strip price may help provide investors with an understanding of the impact of the currently expected oil, natural gas and NGLs price environment to our proved reserves. However, the use of this 5-year NYMEX forward strip price is not necessarily indicative of management’s overall outlook on future oil, natural gas and NGLs prices.

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Emergence from Voluntary Reorganization under 2017 Chapter 11 Proceedings

On February 1, 2017, the 2017 Debtors filed the 2017 Bankruptcy Petitions, and the 2017 Chapter 11 Cases commenced under Chapter 11 of the Bankruptcy Code in the 2017 Bankruptcy Court. The 2017 Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.” The 2017 Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on the Effective Date. The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date.

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Results of Operations

In addition to adopting fresh-start accounting, the Successor also adopted the successful efforts method of accounting as of July 31, 2017. Prior to July 31, 2017, the Predecessor used the full-cost method of accounting. Further, in conjunction with the application of fresh-start accounting, we adopted ASC Topic 606 which had the effect of increasing revenues and expenses by $19.2 million during the five months ended December 31, 2017. The results of operations of the Successor and the Predecessor are not comparable in 2017 nor are they individually comparable with prior periods. We believe however, that production volumes, oil, natural gas and NGLs revenues, lease operating expenses and production and other taxes are generally comparable. Consequently, certain of the tables and discussions below include combined results of the Predecessor and the Successor together for the periods in 2017 for these operational items. We believe this combined presentation gives the reader a better understanding of our operational results in 2017.

The following table sets forth selected financial and operating data for the periods indicated.

	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			$	—

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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)

Revenues

Oil, natural gas and NGLs sales were $469.5 million , $205.6 million, and $246.6 million for the year ended December 31, 2018 , the five months ended December 31, 2017 (Successor), and the seven months ended July 31, 2017 (Predecessor), respectively. The key revenue measurements were as follows:

		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.

The overall increase in oil, natural gas and NGLs sales during 2018 compared to 2017 was due in part to the increase in the average realized oil and natural gas prices, excluding hedges. The increase in average realized oil price is primarily due to a higher average NYMEX crude oil price, which increased 27% as compared to the same period in 2017. This was partially offset by regional basis differentials widening in 2018. Specifically, industry activity is heavily focused in the Permian Basin, and as a result Midland Cushing crude oil differentials have widened during 2018. Our natural gas and NGLs revenues were also higher in 2018 due to the full year impact of Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC Topic 606”), which we adopted in August 2017, where we reclassified gathering, transportation, and processing fees related to certain of our natural gas and NGLs marketing and processing agreements of $39.9 million in 2018 compared to

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$19.2 million during the Successor period in 2017. Refer to Note 4 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details.

The increase in sales due to higher average realized oil price and the change in presentation was partially offset by a decrease in average realized natural gas price, primarily due to a lower average NYMEX natural gas price, which decreased 1%, as compared to the same period in 2017. This decrease in realized pricing is attributable not only to a decrease in NYMEX pricing but also the widening in regional basis differentials during 2018, specifically Rockies gas basis, which is approximately 70% of our total natural gas production.

On a Mcfe basis, our total production decreased by 10,196 MMcfe or 7% for the year ended December 31, 2018 over the comparable period in 2017. The increase in sales due to pricing and the change in presentation was partially offset by an overall decrease in average daily production which decreased to approximately 346 MMcfe/day from approximately 364 MMcfe/day and 381 MMcfe/day for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, or approximately 374 MMcfe/day for the year ended December 31, 2017 (Predecessor). The decrease in average daily production was a result of the divestitures completed during 2017 and 2018.

On a Mcfe basis, crude oil production accounted for 15% 16% and 17% of our production during the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Natural gas accounted for 70% during the year ended December 31, 2018 (Successor), compared to 69% , during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor). On a Mcfe basis, NGLs production accounted for 15% , 14% , and 15% of our production during the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively.

Hedging and Price Risk Management Activities

We recognized a net loss on commodity derivative contracts of $9.3 million , $55.9 million and $24.9 million during the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Net cash settlements on matured commodity derivative contracts included payments of $80.3 million , $12.2 million and receipts of $0.01 million during the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. In addition, we paid net cash settlements of $4.1 million on the monetization of commodity derivative contracts that were terminated as they relate to production of our divested properties during the five months ended December 31, 2017 (Successor). Our hedging program is intended to mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and, by us paying the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because our hedges are currently not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected in our consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses on a per Mcfe basis were $1.08 , $1.09 and $1.08 for the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. The decrease in lease operating expenses is primarily due to lower production volumes as a result of decreased operational activity and divestitures completed in 2017 and 2018. Overall, spending during 2018 decreased as compared to 2017 as a result of our continued focus on cost efficiency measures.

Transportation, gathering, processing and compression fees represent third-party costs related to certain of our natural gas and NGLs marketing and processing agreements. These expenses were $39.9 million and $19.2 million for the year ended December 31, 2018 (Successor) and the five months ended December 31, 2017 (Successor), respectively, due to the adoption of

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Topic ASC 606 in conjunction with fresh-start accounting. In the Predecessor period, these costs were included in the net proceeds received from processing; however, natural gas and NGLs revenues and related marketing and processing costs are recognized on a gross basis effective August 1, 2017. Refer to Note 4 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state and county and are based on the value of our reserves. As a percentage of wellhead revenues, production, severance, and ad valorem taxes was 8.3% , 6.4% and 8.6% for the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively.

The percentage was lower during the Successor period primarily due to higher natural gas and NGLs revenues as they were presented gross of gathering, transportation, and processing fees of $39.9 million and $19.2 million , for the year ended December 31, 2018 , the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, related to certain of our natural gas and NGLs marketing and processing agreements with the adoption of ASC Topic 606. Natural gas and NGLs revenues prior to August 1, 2017 were presented net of these fees. We record and remit production taxes based on net proceeds received from processing related to these contracts. When using net proceeds in the calculation, the effective tax rate for the current period is 9.1%

Depreciation, depletion, amortization and accretion was $150.1 million , $71.3 million and $58.4 million for the year ended December 31, 2018 (Successor), for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. The increase in depreciation, depletion, amortization, and accretion expense is due to a higher amortization base as a result of the application of fresh-start accounting which led to a corresponding increase in the depletion rate per equivalent unit of production for the Successor period.

We adjust our depletion rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs. Thus, our depletion rate could change significantly in the future. Depletion expense is not comparable between Successor and Predecessor periods as a result of our implementation of fresh-start accounting upon emergence from bankruptcy, whereupon the carrying value of our proved oil and gas properties on our balance sheet was recorded at fair value. Also upon emergence, we changed our method of accounting for oil and gas exploration and development activities from the full-cost method to the successful-efforts method of accounting. Depreciation, depletion, amortization and accretion expense per Mcfe was $1.19 $1.28 and $0.72 for the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively.

An impairment of oil and natural gas properties of $29.7 million was recognized during the year ended December 31, 2018 (Successor) which primarily relates to the reduced value of certain of our operating districts. The write downs primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold and a reduction in the value of certain of our operating districts due to a decline in forward natural gas prices. In addition, an impairment of oil and natural gas properties of $47.6 million was recognized during the five months ended December 31, 2017 (Successor) as a result of a downward revision of estimated proved reserves at the measurement date of December 31, 2017. The impairment charge is related to the reduced value of certain of our operating districts resulting from lower forward prices and a faster than expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future development potential, rather than in areas with little upside.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. During the year ended December 31, 2018 , the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), selling, general and administrative expenses were $43.6 million , $21.6 million and $23.0 million , respectively. Selling, general and administrative expenses in 2017 have been impacted by costs incurred in connection with the 2017 Chapter 11 Cases. In addition, the Company made management severance payments in 2017.

 

In addition, we incurred non-cash compensation expense of $2.3 million , $0.1 million and $5.8 million for the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Upon emergence, all unvested equity grants under the Predecessor’s Long-Term Incentive Plan (the “Predecessor Incentive Plan”) that were outstanding immediately before August 1, 2018 were canceled and of no further force or effect as of August 1, 2018. In addition, on August 1, 2018, the Predecessor’s Incentive Plan was canceled and extinguished, and participants in the Predecessor’s Incentive Plan received no payment or other distribution on account of the Incentive Plan. Please read Note 11 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, for further discussion about the Successor Management Incentive Plan.

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Other Income and Expense

Interest expense was $62.9 million , $24.2 million and $35.3 million during the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Interest expense was higher in 2018 due to higher average interest rates. In addition, the Predecessor period was lower primarily due to the discontinuance of interest on its senior notes that were canceled as part of its 2017 Chapter 11 Cases.

During the year ended December 31, 2018 (Successor) and the five months ended December 31, 2017 (Successor), the Company recorded a net gain on the sale of oil and natural gas properties of approximately $4.7 million and $4.5 million , respectively.

Reorganization Items

We incurred reorganization costs of $3.7 million and $6.5 million for the year ended December 31, 2018 (Successor) and the five months ended December 31, 2017 (Successor), respectively. Reorganization items include expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items represent professional fees for post-petition expenses. We also incurred a reorganization gain of $908.5 million for the seven months ended July 31, 2017 (Predecessor) as a result of the gain on the discharge of debt and fresh-start adjustments upon emergence from the 2017 Chapter 11 Cases. Please read Note 15 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details.

Capital Resources and Liquidity

Overview

Historically, we have obtained financing through proceeds from bank borrowings, cash flow from operations and from the public equity and debt markets to provide us with the capital resources and liquidity necessary to operate our business. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves.

Liquidity After Filing Under Chapter 11 of the United States Bankruptcy Code

 

Subject to certain exceptions under the Bankruptcy Code, the filing of the 2019 Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the 2019 Debtors or their property to recover, collect or secure a claim arising prior to the filing of the 2019 Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the 2019 Debtors, or to create, perfect or enforce any lien against the 2019 Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

 

The Bankruptcy Court has approved payment of certain pre-petition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, utilities, insurance, surety bond premiums as well as payments to critical vendors and possessory lien vendors. The Bankruptcy Court has also approved $20.0 million available on an interim basis under the DIP Credit Agreement. In connection with the 2019 Chapter 11 Cases, on the 2019 Petition Date, the 2019 Debtors filed the DIP Motion seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in the DIP Credit Agreement among the DIP Borrower, the financial institutions or other entities from time to time parties thereto, as lenders, and the DIP Agent. The DIP Motion is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. We can provide no assurances that the DIP Motion will be granted. Despite the liquidity provided by our existing cash on hand, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to our potential failure to meet our debt obligations, some vendors could be reluctant to enter into long-term agreements with us.

 

In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our 2019 Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our 2019 Chapter 11 Cases. The Company believes it has sufficient liquidity, including approximately $21.0

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million of cash on hand as of April 8, 2019 and funds generated from ongoing operations, to fund anticipated cash requirements through the 2019 Chapter 11 Cases for minimum operating and capital expenditures and for working capital purposes. Subject to the Bankruptcy Court entering the Final DIP Order and satisfaction of the conditions under the Final Dip Order and DIP Credit Agreement, the Company will have further liquidity of $45 million under the DIP Credit Agreement. The DIP Credit Agreement’s proceeds, however, may only be used 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 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 as well as final approval by the Bankruptcy Court. As such, the Company expects to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders approving such payments.

 

However, given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate and therefore the 2019 Debtors filed a motion to enter into a DIP Credit Agreement as described above to provide additional liquidity. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the 2019 Chapter 11 Cases, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

Debtor-in-Possession Financing

 

In connection with the 2019 Chapter 11 Cases, on the 2019 Petition Date, the 2019 Debtors filed the DIP Motion seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in the DIP Credit Agreement among the DIP Borrower, the financial institutions or other entities from time to time parties thereto, as lenders, the DIP Agent and as issuing bank. The initial lender under the DIP Credit Agreement is Citibank N.A. The DIP Credit Agreement contains the following terms:

•	a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019;

•	a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under 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

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encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;

•	the DIP Credit Agreement is subject to customary covenants, including a requirement that the Company maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10.0 million, prepayment events, events of default and other provisions; and

•	generally, any undrawn commitments on the New Money Facility as of the effective date of a plan of reorganization are contemplated to be converted into an exit RBL facility and the Roll-Up is contemplated to be converted into an exit term loan as of such date.

The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time, and the Roll-Up is subject to the entry of the Final Dip Order by the Bankruptcy Court.

 

Statements of Cash Flows

Net increase (decrease) in cash is summarized as follows (in millions):

		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	)

Cash Flow from Operations

Net cash provided by operating activities for the year ended December 31, 2018 (Successor) was $84.9 million compared to the net cash provided by operating activities for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor) of $ 16.6 million and $80.7 million , respectively.

During the year ended December 31, 2018 (Successor), changes in working capital increased total cash flows by $19.3 million . Contributing to the increase in working capital during 2018 was a $17.0 million increase in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments and a $6.4 million decrease in accounts receivable related to the timing of receipts from production.

During the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), changes in working capital decreased total cash flows by $27.4 million and $26.9 million , respectively. Contributing to the decrease in working capital in each period was the decrease in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments. The increase in accounts receivable of $ 11.4 million for the five months ended December 31, 2017 (Successor) also contributed to the decrease in working capital while the decrease in accounts receivable of $34.8 million offset the decrease in working capital during the seven months ended July 31, 2017 (Predecessor).

The change in the fair value of our derivative contracts are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities in the periods ended 2018 and 2017 .

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGLs prices. Oil, natural gas and NGLs prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic and political activity, weather and other factors beyond our control. Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program as well as the prices of oil, natural gas and NGLs. We entered into derivative contracts to reduce the impact of oil, natural gas and NGLs price

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volatility on operations. During 2018 , we primarily used fixed-price swaps, basis swaps and collars to hedge oil and natural gas prices.

 

We anticipate that our cash flow from operations, expected dispositions of oil and natural gas properties or asset sales as allowed under our credit agreements will exceed our planned capital expenditures and other cash requirements for the year ended December 31, 2019 . However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $30.7 million for the year ended December 31, 2018 (Successor) compared to net cash used in investing activities of $29.5 million for the five months ended December 31, 2017 (Successor) and net cash provided by investing activities of $76.8 million for the seven months ended July 31, 2017 (Predecessor).

During the year ended December 31, 2018 (Successor), we used cash of $74.8 million for the drilling and development of oil and natural gas properties and $57.8 million for deposits and prepayments related to the drilling and development of oil and natural gas properties. In addition, we received proceeds from the sale of oil and natural gas properties of $102.2 million .

During the five months ended December 31, 2017 (Successor), we spent $34.7 million on oil and natural gas capital expenditures and $31.0 million for deposits and prepayments related to the drilling and development of oil and natural gas offset by the proceeds from the sale of oil and natural gas properties of $36.1 million .

The primary source of net cash provided by investing activities was the proceeds from the sale of oil and natural gas properties of $126.4 million for the seven months ended July 31, 2017 (Predecessor). In addition, we spent $25.7 million on oil and natural gas capital expenditures and $23.7 million for deposits and prepayments related to the drilling and development of oil and natural gas properties.

The Board approved, subject to the approval of the DIP Agent and the agent under the Successor Credit Facility, a capital expenditures budget for 2019 of approximately $53.0 million compared to the $124.9 million we spent in 2018 . Our 2019 capital expenditures budget includes approximately $24.0 million of drilling and completion capital focused on the core growth assets of the Green River and Arkoma Basins. If our 2019 capital expenditure budget is approved by the DIP Agent and the agent under the Successor Credit Facility, we expect to spend approximately $15.0 million of the drilling capital budget in the Arkoma Basin where we will participate as a non-operated partner in the drilling and completion of horizontal wells targeting the Woodford and Mayes formations. This program is a continuation of our 2018 one rig program with Newfield Exploration Company, (“Newfield”). The acquisition of Newfield by Encana Corporation has delayed the completion of the program. However, we anticipate further evaluation of the scope and timing of this project to recommence later this fiscal year. Furthermore, we expect to spend approximately $9.0 million in the Green River Basin at the Pinedale field where we participate as a non-operated partner in the drilling of vertical natural gas wells with Ultra Petroleum Corporation and Pinedale Energy Partners. In addition to our drilling and completion programs, we expect to spend approximately $8.0 million on other uplift projects, primarily in the Permian New Mexico Red Lake field, where we will expand on our successful 2018 operated Yeso recompletion and commingle program. The remaining $21.0 million of the capital program will be spent on maintenance and land projects that include safety and environmental compliance, compressor overhauls, facility work, returning wells to production that go offline during the year and other capital required to maintain reserves and operations.

 

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $26.2 million for the year ended December 31, 2018 (Successor) compared to net cash used in financing activities of approximately $ 33.1 million and $151.5 million for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively.

Net cash used in financing activities during the year ended December 31, 2018 (Successor) included cash of $186.9 million that was used for repayments of debt and $1.5 million was paid for financing costs. Additionally, we received net proceeds from borrowings under the Revolving Loan of $162.6 million .

Net cash used in financing activities during the five months ended December 31, 2017 (Successor) included $42.1 million for repayments of debt offset by proceeds of $9.8 million from borrowings under the Revolving Loan.

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The primary drivers of net cash used in financing activities for the seven months ended July 31, 2017 (Predecessor) were repayments of debt of approximately $41.6 million under the Predecessor Credit Facility, repayment of debt of $500.3 million under the Predecessor Credit Facility in accordance with the Plan and payment for debt financing costs of $9.4 million. In addition, net cash provided by financing activities included $275.0 million for proceeds from rights offerings and second lien investment and $125.0 million for proceeds from the Term Loan.

Debt and Credit Facilities

Acceleration of Debt Obligations

As of December 31, 2018 and March 31, 2019, VNG was not in compliance with certain covenants under the Successor Credit Facility. Accordingly, all amounts due under the Debt Instruments are classified as current in the accompanying consolidated balance sheet as of December 31, 2018. The commencement of the 2019 Chapter 11 Cases described above is an event of default that accelerated the 2019 Debtors’ obligations under the Debt Instruments. Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code.

•	$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.

Going Concern Assessment

We have concluded that there is substantial doubt about our ability to continue as a going concern and the report of the independent registered public accounting firm that accompanies the audited consolidated financial statements for the year ended December 31, 2018 included in this Annual Report on Form 10-K contains an explanatory paragraph regarding substantial doubt about our ability to continue as a going concern due to the filing of the 2019 Chapter 11 Cases.

Successor Credit Facility

 

On August 1, 2017, VNG, as borrower, entered into the Successor Credit Facility. Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loan”). The initial borrowing base available under the Successor Credit Facility as of August 1, 2017 was $850.0 million and the aggregate principal amount of Revolving Loan outstanding under the Successor Credit Facility as of August 1, 2017 was $730.0 million . The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). On December 21, 2017, the borrowing base was reduced to $825.0 million following the completion of the sale of our properties in the Williston Basin and was further reduced to $765.2 million following the completion of the sale of certain of our oil and natural gas properties during the first half of 2018.

In July 2018, the Company entered into the Second Amendment to the Successor Credit Facility (the “Second Amendment”) among the Company, the Administrative Agent and the lenders party thereto. Among other things, the Second Amendment reduced the borrowing base from $765.2 million to $729.7 million . The completion of additional divestitures for the remainder of 2018 also resulted in the reduction of our borrowing base to $682.3 million as of December 31, 2018 . Please read Note 5 in the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further discussion on our divestitures.

During the year ended December 31, 2018 , we borrowed $162.6 million under the Revolving Loan and made repayments under the Revolving Loan and Term Loan of $181.7 million . As discussed in Note 5, “Divestitures,” the $102.2 million of net cash proceeds received from the sale of properties were used to pay down debt. We used borrowings under the Revolving Loan to partially pay for capital expenditures incurred in 2018 and advances to operators for activities to be completed in 2019.

 

At December 31, 2018 , there were $682.1 million of outstanding borrowings under the Revolving Loan, which was fully drawn.

The borrowing base under the Successor Credit Facility is subject to adjustments from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the lenders’ petroleum engineers utilizing the lenders’ internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves.

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The maturity date of the Successor Credit Facility is February 1, 2021 with respect to the Revolving Loan and May 1, 2021 with respect to the Term Loan. Until the maturity date for the Term Loan, the Term Loan shall bear an interest rate equal to (i) the alternative base rate plus an applicable margin of 6.50% for an Alternate Base Rate loan or (ii) adjusted LIBOR plus an applicable margin of 7.50% for a Eurodollar loan. Until the maturity date for the Revolving Loan, the Revolving Loan shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 1.75% to 2.75% , based on the borrowing base utilization percentage under the Successor Credit Facility or (ii) adjusted LIBOR plus an applicable margin of 2.75% to 3.75% , based on the borrowing base utilization percentage under the Successor Credit Facility. The amounts outstanding under our Successor Credit Facility were subject to a variable interest rate of 6.27% and 4.90% at December 31, 2018 and 2017 , respectively. The Term Loan was subject to a variable interest rate of 9.96% and 8.90% at December 31, 2018 and 2017 , respectively.

Unused commitments under the Successor Credit Facility will accrue a commitment fee of 0.5% , payable quarterly in arrears.

VNG may elect, at its option, to prepay any borrowing outstanding under the Revolving Loan without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Successor Credit Facility). VNG may be required to make mandatory prepayments of the Revolving Loan in connection with certain borrowing base deficiencies or asset divestitures.

VNG is required to repay the Term Loans on the last day of each March, June, September and December (commencing with the first full fiscal quarter ended after the Effective Date), in each case, in an amount equal to 0.25% of the original principal amount of such Term Loans and, on the Maturity Date, the remainder of the principal amount of the Term Loans outstanding on such date, together in each case with accrued and unpaid interest on the principal amount to be paid but excluding the date of such payment. The table below shows the amounts of required payments under the Term Loan for each year as of December 31, 2018 (in thousands):

 

Year		Required Payments
2019		$	1,250
2020		1,250
2021 through Maturity date		120,938

Additionally, if (i) VNG has outstanding borrowings, undrawn letters of credit and reimbursement obligations in respect of letters of credit in excess of the aggregate revolving commitments or (ii) unrestricted cash and cash equivalents of VNG and the Guarantors (as defined below) exceeds $35.0 million as of the close of business on the most recently ended business day, VNG is also required to make mandatory prepayments, subject to limited exceptions.

The obligations under the Successor Credit Facility are guaranteed by the Successor and all of VNG’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of VNG’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of VNG’s and the Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of VNG, subject to certain limited exceptions.

The Successor Credit Facility contains certain customary representations and warranties, including, without limitation: organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; locations of businesses and offices; properties and titles; maintenance of properties; gas imbalances; prepayments; marketing of production; swap agreements; use of proceeds; solvency; anti-corruption laws and sanctions; and security instruments.

The Successor Credit Facility also contains certain affirmative and negative covenants, including, without limitation: delivery of financial statements; notices of material events; existence and conduct of business; payment of obligations; performance of obligations under the Successor Credit Facility and the other loan documents; operation and maintenance of properties; maintenance of insurance; maintenance of books and records; compliance with laws and regulations; compliance with environmental laws and regulations; delivery of reserve reports; delivery of title information; requirement to grant additional collateral; compliance with ERISA; requirement to maintain commodity swaps; maintenance of accounts; restrictions on indebtedness; liens; dividends and distributions; repayment of permitted unsecured debt; amendments to certain agreements; investments; change in the nature of business; leases (including oil and gas property leases); sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges;

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dividend restrictions; marketing activities; gas imbalances; take-or-pay or other prepayments; swap agreements and transactions, and passive holding company status.

The Successor Credit Facility also contains certain financial covenants, as amended under the Second Amendment, including the maintenance of:

(i)	the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available, determined as of the last day of the fiscal quarter ending in the following periods:

Period		Ratio
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.

The calculation of EBITDA, as defined under the Second Amendment, among other things, include addbacks in respect of certain exploration expenses, as well as third party fees, costs and expenses in connection with the Plan of Reorganization, also defined in the Second Amendment and herein the Final Plan, together with related severance costs, subject to certain limitations.

The Successor Credit Facility also contains certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

As of December 31, 2018 and March 31, 2019, VNG was not in compliance with certain of these covenants under the Successor Credit Facility. Accordingly, all amounts due under the Successor Credit Facility are classified as current in the accompanying consolidated balance sheet as of December 31, 2018.The commencement of the 2019 Chapter 11 Cases constituted an event of default that accelerated the Company’s obligations under Successor Credit Facility.

Any efforts to enforce the Company’s obligations under the Successor Credit Facility are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Successor Credit Facility are subject to the applicable provisions of the Bankruptcy Code.

Senior Secured Second Lien Notes due 2024

 

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of New Notes to certain eligible holders of the Predecessor’s second lien notes in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The New Notes were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

The obligations under the New Notes are guaranteed by all of the Company’s subsidiaries (“Second Lien Guarantors”) subject to limited exceptions, and secured on a second-priority basis by substantially all of the Company’s and the Second Lien Guarantors’ assets, including, without limitation, liens on the total value of the Company’s and the Second Lien Guarantors’ oil

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and gas properties, and pledges of stock of all other direct and indirect subsidiaries of the Company, subject to certain limited exceptions.

 

The New Notes are governed by the Amended and Restated Indenture, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem the our Common Stock or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from the Company’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the New Notes achieve an investment grade rating from each of Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., no default or event of default under the Amended and Restated Indenture exists, and the Company delivers to the Trustee an officers’ certificate certifying such events, many of the foregoing covenants will terminate.

 

The Amended and Restated Indenture also contains customary events of default, including (i) default for thirty ( 30 ) days in the payment when due of interest on the New Notes; (ii) default in payment when due of principal of or premium, if any, on the New Notes at maturity, upon redemption or otherwise; (iii) non-compliance with the affirmative and negative covenants; (iv) failure to file disclosures in the time period stipulated; and (v) certain events of bankruptcy or insolvency with respect to the Company or any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that taken together would constitute a significant subsidiary. As of December 31, 2018 and March 31, 2019, the Company was not in compliance with certain of these covenants. Although the Company failed to file its annual report on Form 10-K for the year ended December 31, 2018 in the time period stipulated in the Amended and Restated Indenture, the Company filed such report within the cure period provided under the Amended and Restated Indenture.

The filing of the 2019 Chapter 11 Cases constituted an event of default under the Amended and Restated Indenture causing all outstanding New Notes to become due and payable immediately without further action or notice.

 

Interest is payable on the New Notes on February 15 and August 15 of each year, beginning on February 15, 2018. The New Notes will mature on February 15, 2024.

 

At any time prior to February 15, 2020, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the New Notes issued under the Amended and Restated Indenture, with an amount of cash not greater than the net cash proceeds of certain equity offerings, at a redemption price equal to 109% of the principal amount of the New Notes, together with accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% of the aggregate principal amount of the New Notes originally issued under the Amended and Restated Indenture remain outstanding after such redemption, and (ii) the redemption occurs within one hundred eighty ( 180 ) days of the equity offering.

 

On or after February 15, 2020, the New Notes will be redeemable, in whole or in part, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

 

Year		Percentage
2020		106.75	%
2021		104.50	%
2022		102.25	%
2023 and thereafter		100.00	%

 

In addition, at any time prior to February 15, 2020, the Company may on any one or more occasions redeem all or a part of the New Notes at a redemption price equal to 100% of the principal amount thereof, plus the Applicable Premium (as defined in the Amended and Restated Indenture) as of, and accrued and unpaid interest, if any, to the date of redemption.

Any efforts to enforce the Company’s obligations under the Amended and Restated Indenture are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Amended and Restated Indenture are subject to the applicable provisions of the Bankruptcy Code.

Lease Financing Obligations

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On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contained an early buyout option for the Company to purchase the equipment for $16.0 million on February 10, 2019. The Company did not exercise that option. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16% .

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Critical Accounting Policies and Estimates

 

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We have discussed the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read   Note 1 of the Notes to the Consolidated Financial Statements included in Part II, Item 8 of this Annual Report, for a discussion of additional accounting policies and estimates made by management.

Accounting Policies

Upon emergence from the 2017 Chapter 11 Cases on August 1, 2017, we had multiple changes to our accounting policies:

•

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;

 

Oil and Natural Gas Properties

Under GAAP, there are two allowed methods of accounting for oil and natural gas properties: the full cost method and the successful efforts method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the calculation of depreciation, depletion and amortization expense, and the assessment of impairment of oil and natural gas properties.

Prior to July 31, 2017, we followed the full cost method of accounting. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and ceiling test limitations. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurred on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transferred unproved property costs to the amortizable base when unproved properties were evaluated as being impaired and as exploratory wells were determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month average price discounted at 10% , plus the lower of cost or fair market value of unproved properties. Please read further discussion below.

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On August 1, 2017, we adopted the successful efforts method of accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties.

Under the successful efforts method, we capitalize the costs of acquiring unproved and proved oil and natural gas leasehold acreage. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. Development costs are capitalized, including the costs of unsuccessful and successful development wells and the costs to drill and equip exploratory wells that find proved reserves. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are expensed as incurred.

Depreciation, depletion and amortization

Depreciation, depletion and amortization of the leasehold and development costs that are capitalized into proved oil and natural gas properties are computed using the units-of-production method, at the district level, based on total proved reserves and proved developed reserves, respectively. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are assessed for impairment in accordance with Accounting Standards Codification Topic 360 “ Property, Plant and Equipment”, when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in oil, natural gas and NGLs prices, but at least annually. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If, the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value.

Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

During the five months ended December 31, 2017, the Company recorded impairment charges of $47.6 million which

primarily relates to the reduced value of certain of our operating districts resulting from lower forward prices and faster than

expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future

development potential, rather than in areas with little upside.

During the year ended December 31, 2018 , the Company recorded impairment charges of $29.7 million which primarily relates to the reduced value of certain of our operating districts. The write downs primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold and a reduction in the value of certain of our operating districts due to a decline in forward natural gas prices.

Fresh-Start Accounting

In accordance with ASC Topic 852, we were required to apply fresh-start accounting upon its emergence from the 2017 Chapter 11 Cases. We evaluated transaction activity between July 31, 2017 and August 1, 2017 and concluded that July 31, 2017 was appropriate for the adoption of fresh-start accounting which resulted in the Successor Company becoming a new entity for financial reporting purposes as of July 31, 2017.

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We adopted fresh-start accounting in accordance with the provisions set forth in ASC Topic 852 as (i) the fair value of our total assets or the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of emergence from the 2017 Chapter 11 Cases, our consolidated financial statements subsequent to July 31, 2017 are not comparable to our consolidated financial statements prior to July 31, 2017; as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Refer to Note 15 of the Notes to the Consolidated Financial Statements, included under Part II, Item 8 of this Annual Report, for more details.

Asset Retirement Obligation

 

We have obligations to remove tangible equipment and restore land at the end of an oil or natural gas well’s life. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and the decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation. These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of the obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. 

Oil, Natural Gas and NGLs Reserve Quantities

Our reservoir engineers estimate proved oil and gas reserves accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion, amortization and accretion. Proved oil and gas reserves are defined by the SEC as the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Although our reservoir engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation and depletion rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

Revenue Recognition

Impact of ASC Topic 606 Adoption

In conjunction with the application of fresh-start accounting, we adopted ASC Topic 606. We adopted using the modified retrospective method, which fresh-start accounting allows, to apply the new standard to all new contracts entered into after August 1, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of July 31, 2017. ASC Topic 606 supersedes previous revenue recognition requirements in ASC Topic 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services.

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The impact of adoption on our operating results in the year of adoption is as follows (in thousands):

	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	)		$	—

Changes to sales of natural gas and NGLs, and transportation, gathering, processing, and compression expense are due to the conclusion that the Company represents the principal and the ultimate third party is our customer in certain natural gas processing and marketing agreements with certain midstream entities in accordance with the control model in ASC Topic 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC Topic 605 Topic where we acted as the agent and the midstream processing entity was our customer. As a result, we modified our presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Transportation, gathering, processing and compression expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as transportation, gathering, processing, and compression expense.

Revenue from Contracts with Customers

Sales of oil, natural gas and NGLs are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

Natural gas and NGLs Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether we are the principal or the agent in the transaction. For those contracts where we have concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in our Statement of Operations. Alternatively, for those contracts where we have concluded that we are the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing.

In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in our consolidated statements of operations.

Oil sales

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Our oil sales contracts are generally structured in one of the following ways:

•	We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

•

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of these third-party transportation fees in our consolidated statements of operations.

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC Topic 606, for the period from August 1, 2017 through December 31, 2018 , there was no material impact to the financial statements due to this change in accounting for our production imbalances.

Transaction price allocated to remaining performance obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC Topic 606.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from August 1, 2017 through December 31, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

Price Risk Management Activities

We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, we primarily use fixed-price swaps and collars to hedge oil, and natural gas and NGLs prices.

Under ASC Topic 815, Derivatives and Hedging (“ASC Topic 815”), the fair value of hedge contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and since we do not apply hedge accounting, the change in fair value of the hedge contracts are reflected in earnings.  If the hedge contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income,” and changes in the fair value do not affect net income

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until the contract is settled. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as gain or loss on commodity derivatives.

Recently Issued Accounting Pronouncements

Please read Note 2 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for a detailed list of recently issued accounting pronouncements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC Topic 842) (“ASU 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. ASU 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The ASU requires adoption using a modified retrospective transition approach with either (a) periods prior to the adoption date being recast or (b) a cumulative-effect adjustment recognized to the opening balance of retained earnings on the adoption date with prior periods not recast.

We adopted ASU No. 2016-02 as of January 1, 2019, using the targeted improvement transition option included in ASU No. 2018-11 - Leases (Topic 842). The targeted improvement approach allows us to apply the standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, we elected certain practical expedients permitted under the transition guidance within the new standard, which allowed us to carry forward the historical lease classification and not capitalize leases with terms of one year or less without a purchase option. In addition, it allowed us not to separate lease and non-lease components. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. We are substantially complete in assessing the transitional impact from adopting the standard. A third-party software tool has been implemented that will assist with the initial adoption and ongoing compliance of the standard. We are implementing new business processes, internal controls, and accounting policies. We are also in the process of drafting disclosures to satisfy the standard's requirements. While we expect an increase in assets and liabilities, as well as additional disclosures, we are still assessing the impact of this ASU on our consolidated financial statements.

Off-Balance Sheet Arrangements

We currently do not have off-balance sheet arrangements.

 

Contingencies

 

The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. As of December 31, 2018 , there were no material loss contingencies.

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Commitments and Contractual Obligations

A summary of our contractual obligations as of December 31, 2018 is provided in the following table:

		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.

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Non-GAAP Financial Measures

 

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard stockholders/unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that begins with net income (loss) attributable to Vanguard stockholders/unitholders plus net income (loss) attributable to non-controlling interest. The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:

 

•	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.

Adjusted EBITDA is used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption

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of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Successor Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows.

As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.

As a result of the adoption of fresh-start reporting and the effects of the implementation of the Final Plan, our consolidated financial statements subsequent to July 31, 2017 are not comparable to our consolidated financial statements prior to July 31, 2017, and as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA (in thousands). 

		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		)		—				—

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Texas margin taxes		—				—					(634		)		(3,307		)		(266		)		(630		)
Compensation related items		2,282				81					5,797				10,183				18,522				11,710
Reorganization and restructuring costs		3,651				6,488					(908,485		)		3,156				—				—
Severance costs		4,561				—					—				—				—				—
Material costs incurred on strategic transactions		1,398				2,000					—				3,265				11,692				739
Adjusted EBITDA before non-controlling interest		$	137,394			$	81,054				$	115,513			$	433,428			$	396,829			$	421,445
Non-controlling interest attributable to adjustments above		(87		)		(62		)			(271		)		(463		)		—				—
Adjusted EBITDA attributable to Vanguard stockholders/unitholders		$	137,307			$	80,992				$	115,242			$	432,965			$	396,829			$	421,445
(a) These items are included in the net gains (losses) on commodity derivative contracts line item in the consolidated statements of operations as follows:
		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 cash settlements (paid) received on matured commodity derivative contracts		$	(80,266	)		$	(12,174	)			$	7			$	226,876			$	211,723			$	10,187
Change in fair value of commodity derivative contracts		$	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		$	—			$	—				$	—			$	(292	)		$	(5,434	)		$	—
Fair value of derivative contracts acquired that apply to contracts settled during the period		$	—			$	—				$	—			$	(15,285	)		$	(44,761	)		$	(21,306	)
Cash settlements paid on terminated derivative       contracts (b)		$	—			$	(4,140	)			$	—			$	—			$	—			$	—
Fair value of restructured derivative contracts (d)		$	—			$	—				$	—			$	53,955			$	69,515			$	—
Net gains (losses) on commodity derivative contracts		$	(9,259	)		$	(55,857	)			$	(24,887	)		$	(44,072	)		$	169,416			$	163,452

(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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

As a smaller reporting company, we are not required to provide the information required by this Item.

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Index

 

Below is an index to the items contained in this “Item 8. Financial Statements and Supplementary Data.”

			Page
	Report of Independent Registered Public Accounting Firm		89
	Consolidated Statements of Operations		91
	Consolidated Balance Sheets		92
	Consolidated Statements of Equity		93
	Consolidated Statements of Cash Flows		94
	Notes to Consolidated Financial Statements		96
	Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)		129
	Supplemental Oil and Natural Gas Information		131

 

All schedules are omitted as the required information is not applicable or the information is presented in the Consolidated Financial Statements and related notes.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Stockholders

Vanguard Natural Resources, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Vanguard Natural Resources, Inc. (“Successor,” formerly Vanguard Natural Resources, LLC (“Predecessor”)) and subsidiaries as of December 31, 2018 and 2017 (Successor), the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2018 (Successor), the period from August 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through July 31, 2017 (Predecessor) and the related notes (collectively referred to as the “consolidated financial statements”). Successor and Predecessor are collectively referred to as the “Company.” In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2018 and 2017 (Successor), and the results of their operations and their cash flows for the year ended December 31, 2018, the period from August 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through July 31, 2017 (Predecessor) , in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 3 to the consolidated financial statements, the Company failed certain debt covenants as of December 31, 2018 and subsequently filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code on March 31, 2019, which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Notes 1 and 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Change in Basis of Accounting

As discussed in Note 15 to the consolidated financial statements, upon emerging from bankruptcy proceedings on August 1, 2017, the Company became a new entity for financial reporting purposes and applied fresh-start accounting. The Company’s assets and liabilities were recorded at their estimated fair values, which differed materially from the previously recorded amounts. As a result, the consolidated financial statements for the periods following the application of fresh-start accounting are not comparable to the financial statements for previous periods.

Changes in Accounting Principles

As discussed in Note 4 to the consolidated financial statements, the Company changed its method of accounting for revenue recognition upon emergence from bankruptcy and application of fresh start accounting on July 31, 2017 due to the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606).

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for its oil and natural gas properties from the full cost method to the successful efforts method upon emergence from bankruptcy and application of fresh start accounting on July 31, 2017.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles

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used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2008.

 

Houston, Texas

April 15, 2019

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Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

 (in thousands, except per share/unit data)

		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

See accompanying notes to consolidated financial statements.

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Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

As of December 31,

(in thousands, except share data) 

	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

See accompanying notes to consolidated financial statements.

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Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Members’ Equity (Deficit) (Predecessor)

For the Seven Month Period Ended July 31, 2017

(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

 

Consolidated Statement of Stockholders’ Equity (Successor)

For the Year Ended December 31, 2018 and the Five Month Period Ended December 31, 2017

		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

See accompanying notes to consolidated financial statements.

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Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	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		)

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	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

  See accompanying notes to consolidated financial statements.

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Vanguard Natural Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2018

 

Description of the Business:

 

Vanguard Natural Resources, Inc. is an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. The Company is currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of December 31, 2018 , we own properties and oil and natural gas reserves primarily located in nine operating basins:

•	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.

References to the “Successor” are to Vanguard Natural Resources, Inc., formerly known as VNR Finance Corp., and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Acquisition Partnership II, L.P. (“ERAP II”).

References to the “Predecessor” are to Vanguard Natural Resources, LLC, individually and collectively with its subsidiaries.

References to “us,” “we,” “our,” the “Company,” “Vanguard,” or “VNR” or like terms refer to Vanguard Natural Resources, LLC for the period prior to emergence from bankruptcy on August 1, 2017 (the “Effective Date”) and to Vanguard Natural Resources, Inc. for the period as of and following the Effective Date.

1.	Going Concern Assessment

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the existence of covenant defaults and Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. Please see Note 3, “2019 Chapter 11 Proceedings,” for further discussion.

2.    Summary of Significant Accounting Policies

(a)	Basis of Presentation and Principles of Consolidation:

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Our consolidated financial statements are prepared in accordance with U.S. GAAP and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or stockholders equity.

We consolidated the Potato Hills Gas Gathering System as we had the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our condensed consolidated financial statements. On August 1, 2018, we completed the sale of our 51% joint venture interest in Potato Hills Gas Gathering System, including the compression assets relating to the gathering system and our working interest in related oil and natural gas producing properties (the “Potato Hills Divestment”). Please see Note 5, “Divestitures,” for further discussion.

(b)	2019 Chapter 11 Proceedings:

On March 31, 2019 the Company and certain subsidiaries (such subsidiaries, together with the Company, the “2019 Debtors”) filed voluntary petitions for relief (collectively, the “2019 Bankruptcy Petitions” and, the cases commenced thereby, the “2019 Chapter 11 Cases”) under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court. See Note 3 for a discussion of the Chapter 11 proceedings.

(c)	New Pronouncements Recently Adopted:

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (ASC Topic 230): Restricted Cash (“ASU 2016-18”), which is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. The Company adopted ASU 2016-18 retrospectively effective January 1, 2018. The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the condensed consolidated statements of cash flows and disclosure reconciling cash and cash equivalents presented on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statements of cash flows. The adoption of this guidance did not have a material impact on the Company’s financial position of results of operations as the impact was primarily related to presentation.

(d)	New Pronouncements Issued But Not Yet Adopted:

In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC Topic 842) (“ASU 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. ASU 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The ASU requires adoption using a modified retrospective transition approach with either (a) periods prior to the adoption date being recast or (b) a cumulative-effect adjustment recognized to the opening balance of retained earnings on the adoption date with prior periods not recast.

We adopted ASU No. 2016-02 as of January 1, 2019, using the targeted improvement transition option included in ASU No. 2018-11 - Leases (Topic 842). The targeted improvement approach allows us to apply the standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, we elected certain practical expedients permitted under the transition guidance within the new standard, which allowed us to carry forward the historical lease classification and not capitalize leases with terms of one year or less without a purchase option. In addition, it allowed us not to separate lease and non-lease components. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. We are substantially complete in assessing the transitional impact from adopting the standard. A third-party software tool has been implemented that will assist with the initial adoption and ongoing compliance of the standard. We are implementing new business processes, internal controls, and accounting policies. We are also in the process of drafting disclosures to satisfy the standard's requirements. While we expect an increase in assets and liabilities, as well as additional disclosures, the adjustments that will be required upon implementation of ASU 2016-02, which we anticipate to be less than $18.0 million , have not been finalized.

(e)	Cash, Cash Equivalents and Restricted Cash:

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows (in thousands):

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		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:

Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

(g)	Oil and Natural Gas Properties - Transition from Full Cost Method to Successful Efforts Accounting Method:

Successor Oil and Natural Gas Properties

Under GAAP, there are two allowed methods of accounting for oil and natural gas properties: the full cost method and the successful efforts method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the calculation of depreciation, depletion, and amortization expense, and the assessment of impairment of oil and natural gas properties.

Prior to July 31, 2017, we followed the full cost method of accounting. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and ceiling test limitations. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurred on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transferred unproved property costs to the amortizable base when unproved properties were evaluated as being impaired and as exploratory wells were determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10% , plus the lower of cost or fair market value of unproved properties. Please see further discussion below.

On August 1, 2017, we adopted the successful efforts method of accounting for our oil and natural gas properties. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties in the Successor.

Under the successful efforts method, we capitalize the costs of acquiring unproved and proved oil and natural gas leasehold acreage. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. Development costs are capitalized, including the costs of unsuccessful and successful development wells and the costs to drill and equip exploratory wells that find proved reserves. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are expensed as incurred.

Depreciation, depletion and amortization

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Depreciation, depletion and amortization of the leasehold and development costs that are capitalized into proved oil and natural gas properties are computed using the units-of-production method, at the district level, based on total proved reserves and proved developed reserves, respectively. Upon sale or retirement of oil and gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are assessed for impairment when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in oil, natural gas and NGLs prices, but at least annually. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If, the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value.

Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

During the five months ended December 31, 2017, the Company recorded impairment charges of $47.6 million which

primarily relates to the reduced value of certain of our operating districts resulting from lower forward prices and faster than

expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future

development potential, rather than in areas with little upside.

During the year ended December 31, 2018 , the Company recorded impairment charges of $29.7 million which primarily relates to the reduced value of certain of our operating districts. The write downs primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold and a reduction in the value of certain of our operating districts due to a decline in forward natural gas prices.

(h)	Asset Retirement Obligations:

We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate.  These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.

(i)	Revenue Recognition and Gas Imbalances:

In conjunction with fresh-start accounting, the Company elected to early adopt ASC 606 - Revenue from Contracts with Customers (“ASC 606”) effective August 1, 2017. See Note 4, “Impact of ASC 606 Adoption,” for further details related to the Company’s adoption of this standard.

(j)	Concentrations of Credit Risk:

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable, derivative contracts and accounts payable. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

 

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At December 31, 2018 and 2017 , the cash and cash equivalents were primarily concentrated in one financial institution. We periodically assess the financial condition of the institutions and believe that any possible credit risk is minimal.

The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales during the periods indicated:

		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%

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

(k)	Use of Estimates:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related future cash flows, the fair value of derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion, income taxes and estimated enterprise value and fair values of assets and liabilities under the provisions of ASC 852 fresh-start accounting. Actual results could differ from those estimates.

(l)	Price and Interest Rate Risk Management Activities:

We have entered into derivative contracts primarily with counterparties that are also lenders under the Successor Credit Facility (defined in Note 6) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2018 , our derivative transactions included the following:

•	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

price differential and amounts stated under the terms of the contract.

•	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.

Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings since specific hedge accounting criteria are not met. Gains or losses on derivative contracts are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.

(m)	Income Taxes:

The Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, in which the taxable income or loss of the Predecessor were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.

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Effective upon consummation of the Final Plan, as defined below, the Successor became a C corporation subject to federal and state income taxes. As a C corporation, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company incurred a net taxable loss in the current taxable period. Thus no current income taxes are anticipated to be paid and no net benefit will be recorded in the Company’s condensed consolidated financial statements due to the full valuation allowance on the tax assets.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

Refer to Note 13, “Income Taxes,” for more information on the Company’s accounting for income taxes.

(n)	Emergence from Voluntary Reorganization under Chapter 11 in 2017:

On February 1, 2017 (the “2017 Petition Date”), the Predecessor and certain of its subsidiaries (the “2017 Debtors”) filed voluntary petitions for relief (collectively, the “2017 Bankruptcy Petitions” and, the cases commenced thereby, the “2017 Chapter 11 Cases”) under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “2017 Bankruptcy Court”). During the pendency of the 2017 Chapter 11 proceedings, the 2017 Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the 2017 Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. On July 18, 2017, the 2017 Bankruptcy Court entered the Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Confirmation Order”), which approved and confirmed the 2017 Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Final Plan”). The Company emerged from bankruptcy effective August 1, 2017. Please read Note 14, “Emergence From Voluntary Reorganization Under 2017 Chapter 11 Proceedings” for a discussion of the 2017 Chapter 11 Cases and the Final Plan.

In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), the Successor was required to apply fresh-start accounting upon its emergence from bankruptcy. The Successor evaluated transaction activity between July 31, 2017 and August 1, 2017 and concluded that an accounting convenience date of July 31, 2017 (the “Convenience Date”) was appropriate for the adoption of fresh-start accounting which resulted in the Successor becoming a new entity for financial reporting purposes as of the Convenience Date. See Note 15.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to July 31, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, July 31, 2017. As such, these periods are not comparable, are labeled Successor or Predecessor, and are separated by a bold black line.

3.     2019 Chapter 11 Proceedings

Commencement of Bankruptcy Cases

During the year ended December 31, 2018, the Company had liquidity issues, and it was not in compliance with certain of its debt covenants as of December 31, 2018.

On March 31, 2019, the 2019 Debtors filed the 2019 Bankruptcy Petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The 2019 Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the 2019 Chapter 11 Cases under the caption “In re Vanguard Natural Resources, Inc., et al.”

The subsidiary 2019 Debtors in the 2019 Chapter 11 Cases are VNG, VNRH, VO, EOC, EAC, ERAC, ERUD, ERAP, ERAC II, ERUD II and ERAP II.

No trustee has been appointed and the Company will continue to manage itself and its affiliates and operate their businesses as “debtors-in-possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of

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the Bankruptcy Code and the orders of the Bankruptcy Court. The Company expects to continue its operations without interruption during the pendency of the 2019 Chapter 11 Cases. To assure ordinary course operations, the 2019 Debtors secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize the 2019 Debtors to maintain their existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees.

Debtor-in-Possession Financing

In connection with the 2019 Chapter 11 Cases, on the 2019 Petition Date, the 2019 Debtors filed the DIP Motion seeking, among other things, interim and final approval of the 2019 Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in the DIP Credit Agreement among the DIP Borrower, the financial institutions or other entities from time to time parties thereto, as lenders, and the DIP Agent. The initial lender under the DIP Credit Agreement is Citibank N.A. The DIP Credit Agreement contains the following terms:

•	a super-priority senior secured revolving credit facility in the aggregate amount of up to $65.0 million (the “New Money Facility”), of which $20.0 million was drawn on April 4, 2019;

•	a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under 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.

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The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time, and the Roll-Up is subject to the entry of the Final Dip Order by the Bankruptcy Court. We can provide no assurances that the DIP Motion will be granted.

Acceleration of Debt Obligations

As of December 31, 2018 and March 31, 2019, VNG was not in compliance with certain covenants under the Successor Credit Facility. Accordingly, all amounts due under the Successor Credit Facility and New Notes are classified as current in the accompanying consolidated balance sheet as of December 31, 2018. The commencement of the 2019 Chapter 11 Cases described above is an event of default that accelerated the 2019 Debtors’ obligations under the following debt instruments (the “Debt Instruments”). Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code.

•	$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.

4.  Impact of ASC 606 Adoption

In conjunction with the application of fresh-start accounting, we adopted ASC 606. We adopted using the modified retrospective method, which fresh-start accounting allows us to apply the new standard to all new contracts entered into after August 1, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of July 31, 2017. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services.

The impact of adoption on our operating results in the year of adoption is as follows (in thousands):

	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	)		$	—

Changes to sales of natural gas and NGLs, and transportation, gathering, processing, and compression expense are due to the conclusion that the Company represents the principal and the ultimate third party is our customer in certain natural gas processing and marketing agreements with certain midstream entities in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where we acted as the agent and the midstream processing entity was our customer. As a result, revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Transportation, gathering, processing and compression expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as Transportation, gathering, processing, and compression expense.

Revenue from Contracts with Customers

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Sales of oil, natural gas and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

Natural gas and NGLs Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether we are the principal or the agent in the transaction. For those contracts where we have concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in our consolidated statements of operations. Alternatively, for those contracts where we have concluded the Company is the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing.

In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as Transportation, gathering, processing and compression expense in our consolidated statements of operations.

                 

Oil sales

Our oil sales contracts are generally structured in one of the following ways:

•	We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

•

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of these third-party transportation fees in our consolidated statements of operations.

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC 606, for the period from August 1, 2017 through December 31, 2018 , there was no material impact to the financial statements due to this change in accounting for our production imbalances.

Transaction price allocated to remaining performance obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

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Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. For the year ended December 31, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

5.    Divestitures

2018 Divestitures

During 2018, the Company completed the sale of certain oil and natural gas properties in the Permian Basin, the Green River Basin, Arkoma Basin and in Mississippi. The Company also sold its working interests in related oil and natural gas producing properties located in multiple counties in Texas, Louisiana and Colorado. Additionally, as discussed in Note 2, the Company completed the Potato Hills Divestment on August 1, 2018. Net cash proceeds received from the sale of all of these properties were approximately $102.2 million , subject to customary post-closing adjustments. Additionally, we incurred costs to sell of approximately $3.0 million . These dispositions were treated as asset sales, and resulted in a net gain of approximately $4.7 million , which is included in “net gain (loss) on divestiture of oil and natural gas properties” on the condensed consolidated statement of operations. The net cash proceeds from these divestments were used to pay down outstanding debt under the Successor Credit Facility.

In May 2018, the Company completed the trade of its interests in certain properties in the Green River Basin in exchange for interests in other properties within the same basin. The non-cash exchange was accounted for at fair value and no gain or loss was recognized from the exchange.

2017 Divestitures

On April 2017, we entered into a purchase and sale agreement, as amended, with a third party buyer for the sale of a substantial portion our oil and gas properties located in Glasscock County, Texas (the “Glasscock Divestiture”). The Glasscock Divestiture included the sale of leases with a purchase price of $96.9 million which we closed on May 19, 2017 and in a subsequent transaction on June 30, 2017, we closed the sale of wells related to the assets for an adjusted purchase price of $5.2 million , subject to customary post-closing adjustments. In accordance with the Final Plan, all net cash proceeds received from the Asset Sale were used to pay the lenders under the Predecessor reserve-based credit facility on August 1, 2017.

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”) for a consideration of $36.9 million and $5.0 million related to the relief of asset retirement obligations.

We also completed sales of certain of our other properties located in our various operating areas for an aggregate consideration of approximately $0.4 million and $23.7 million during the five months ended December 31, 2018 (Successor) and seven months ended July 31, 2017 (Predecessor), respectively.

The Glasscock Divestiture and the sale of other oil and natural properties that were completed prior to August 1, 2017 did not significantly alter the relationship between the Predecessor capitalized costs and proved reserves. As such, no gain or loss on sales of oil and natural were recognized and the sales proceeds were treated as a reduction to the carrying value of the Predecessor full cost pool.

As discussed under Note 2, “ Summary of Significant Accounting Policies , ” the Company elected to change its method of accounting for oil and gas exploration and development activities from the full cost method of accounting to the successful efforts method of accounting as of August 1, 2017. Under the successful efforts method, costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is

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recognized currently. The Company recorded a gain of approximately $4.4 million from the Williston Divestiture, which is included in “Net gains (losses) on acquisitions and divestiture of oil and natural gas properties” in our consolidated statement of operations.

6.    Debt

 

Our financing arrangements consisted of the following (in thousands):

						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

(1) Variable interest rate of 6.27% and 4.90% at December 31, 2018 and 2017, respectively.

(2) Variable interest rate of 9.96% and 8.90% at December 31, 2018 and 2017, respectively.

(3) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

(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.

Acceleration of Debt Obligations

As of December 31, 2018 and March 31, 2019, VNG was not in compliance with certain covenants under the Successor Credit Facility. Accordingly, all amounts due under our Successor Credit Facility and New Notes are classified as current in the accompanying consolidated balance sheet as of December 31, 2018. As previously discussed in Note 3, “2019 Chapter 11 Proceedings,” the commencement of the 2019 Chapter 11 Cases on March 31, 2019 constitutes an event of default that accelerated our indebtedness under our Successor Credit Facility and our New Notes. Any efforts to enforce such obligations under the related Successor Credit Facility and the Amended and Restated Indenture are stayed automatically as a result of the filing of the Chapter 11 petitions and the holders’ rights of enforcement in respect of the Successor Credit Facility and the Amended and Restated Indenture are subject to the applicable provisions of the Bankruptcy Code.

 

Successor Credit Facility

 

On the Effective Date, VNG, as borrower, entered into the Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A., as Administrative Agent and Issuing Bank, and the lenders party thereto. Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loan”). The initial borrowing base available under the Successor Credit Facility as of August 1, 2017 was $850.0 million and the aggregate principal amount of Revolving Loan outstanding under the Successor Credit Facility as of August 1, 2017 was $730.0 million . The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). On December 21, 2017, the borrowing base was reduced to $825.0 million following the completion of the sale of our properties in the Williston Basin and was further reduced to $765.2 million following the completion of the sale of certain of our oil and natural gas properties during the first half of 2018.

In July 2018, the Company entered into the Second Amendment to the Successor Credit Facility (the “Second Amendment”) among the Company, the Administrative Agent and the lenders party thereto. Among other things, the Second Amendment

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reduced the borrowing base from $765.2 million to $729.7 million . The completion of additional divestitures for the remainder of 2018 also resulted in the reduction of our borrowing base to $682.3 million as of December 31, 2018 . Please see Note 5 for further discussion on our divestitures.

During the year ended December 31, 2018 , we borrowed $162.6 million under the Successor Credit Facility and made repayments under the Successor Credit Facility and Term Loan of $181.7 million . As discussed in Note 5, “Divestitures,” the $102.2 million of net cash proceeds received from the sale of properties were used to pay down debt. We used borrowings under the Successor Credit Facility to partially pay for capital expenditures incurred in 2018 and advances to operators for activities to be completed in 2019.

 

At December 31, 2018 , there were $682.1 million of outstanding borrowings under the Successor Credit Facility, which was fully drawn.

The borrowing base under the Successor Credit Facility is subject to adjustments from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the lenders’ petroleum engineers utilizing the lenders’ internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves.

The maturity date of the Successor Credit Facility is February 1, 2021 with respect to the Revolving Loan and May 1, 2021 with respect to the Term Loan. Until its maturity date, the Term Loan shall bear an interest rate equal to (i) the alternative base rate plus an applicable margin of 6.50% for an Alternate Base Rate loan or (ii) adjusted LIBOR plus an applicable margin of 7.50% for a Eurodollar loan. Until their maturity date, the Revolving Loan shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 1.75% to 2.75% , based on the borrowing base utilization percentage under the Successor Credit Facility or (ii) adjusted LIBOR plus an applicable margin of 2.75% to 3.75% , based on the borrowing base utilization percentage under the Successor Credit Facility.

Unused commitments under the Successor Credit Facility will accrue a commitment fee of 0.5% , payable quarterly in arrears.

VNG may elect, at its option, to prepay any borrowing outstanding under the Revolving Loan without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Successor Credit Facility). VNG may be required to make mandatory prepayments of the Revolving Loan in connection with certain borrowing base deficiencies or asset divestitures.

VNG is required to repay the Term Loans on the last day of each March, June, September and December (commencing with the first full fiscal quarter ended after August 1, 2017), in each case, in an amount equal to 0.25% of the original principal amount of such Term Loans and, on the Maturity Date, the remainder of the principal amount of the Term Loans outstanding on such date, together in each case with accrued and unpaid interest on the principal amount to be paid but excluding the date of such payment. The table below shows the amounts of required payments under the Term Loan for each year as of December 31, 2018 (in thousands):

 

Year		Required Payments
2019		$	1,250
2020		1,250
2021 through Maturity date		120,938

As discussed above all amounts due under our Successor Credit Facility are classified as current in the accompanying consolidated balance sheet as of December 31, 2018.

Additionally, if (i) VNG has outstanding borrowings, undrawn letters of credit and reimbursement obligations in respect of letters of credit in excess of the aggregate revolving commitments or (ii) unrestricted cash and cash equivalents of VNG and the Guarantors (as defined below) exceeds $35.0 million as of the close of business on the most recently ended business day, VNG is also required to make mandatory prepayments, subject to limited exceptions.

The obligations under the Successor Credit Facility are guaranteed by the Successor and all of VNG’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of VNG’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of VNG’s and the Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of VNG, subject to certain limited exceptions.

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The Successor Credit Facility contains certain customary representations and warranties, including, without limitation: organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; locations of businesses and offices; properties and titles; maintenance of properties; gas imbalances; prepayments; marketing of production; swap agreements; use of proceeds; solvency; anti-corruption laws and sanctions; and security instruments.

The Successor Credit Facility also contains certain affirmative and negative covenants, including, without limitation: delivery of financial statements; notices of material events; existence and conduct of business; payment of obligations; performance of obligations under the Successor Credit Facility and the other loan documents; operation and maintenance of properties; maintenance of insurance; maintenance of books and records; compliance with laws and regulations; compliance with environmental laws and regulations; delivery of reserve reports; delivery of title information; requirement to grant additional collateral; compliance with ERISA; requirement to maintain commodity swaps; maintenance of accounts; restrictions on indebtedness; liens; dividends and distributions; repayment of permitted unsecured debt; amendments to certain agreements; investments; change in the nature of business; leases (including oil and gas property leases); sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; marketing activities; gas imbalances; take-or-pay or other prepayments; swap agreements and transactions, and passive holding company status.

The Successor Credit Facility also contains certain financial covenants, as amended under the Second Amendment, including the maintenance of:

(i)	the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available, determined as of the last day of the fiscal quarter ending in the following periods:

Period		Ratio
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.

The calculation of EBITDA, as defined under the Second Amendment, among other things, include addbacks in respect of certain exploration expenses, as well as third party fees, costs and expenses in connection with the Plan of Reorganization, also defined in the Second Amendment, together with related severance costs, subject to certain limitations.

The Successor Credit Facility also contains certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

As of December 31, 2018 and March 31, 2019, VNG was not in compliance with certain of these covenants under the Successor Credit Facility. Accordingly, all amounts due under the Successor Credit Facility are classified as current in the accompanying consolidated balance sheet as of December 31, 2018. The commencement of the 2019 Chapter 11 Cases constituted an event of default that accelerated the Company’s obligations under Successor Credit Facility.

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Any efforts to enforce the Company’s obligations under the Successor Credit Facility are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Successor Credit Facility are subject to the applicable provisions of the Bankruptcy Code.

New Notes

 

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of New Notes to certain eligible holders of the Predecessor’s second lien notes in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The New Notes were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

The obligations under the New Notes are guaranteed by all of the Company’s subsidiaries (“Second Lien Guarantors”) subject to limited exceptions, and secured on a second-priority basis by substantially all of the Company’s and the Second Lien Guarantors’ assets, including, without limitation, liens on the total value of the Company’s and the Second Lien Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of the Company, subject to certain limited exceptions.

 

The New Notes are governed by the Amended and Restated Indenture, dated as of August 1, 2017 (as amended, the “Amended and Restated Indenture”), by and among the Company, certain subsidiary guarantors of the Company (the “Guarantors”) and Delaware Trust Company, as Trustee (in such capacity, the “Trustee”) and as Collateral Trustee (in such capacity, the “Collateral Trustee”), which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem the Company’s common stock or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from the Company’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the New Notes achieve an investment grade rating from each of Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., no default or event of default under the Amended and Restated Indenture exists, and the Company delivers to the Trustee an officers’ certificate certifying such events, many of the foregoing covenants will terminate.

 

The Amended and Restated Indenture also contains customary events of default, including (i) default for thirty ( 30 ) days in the payment when due of interest on the New Notes; (ii) default in payment when due of principal of or premium, if any, on the New Notes at maturity, upon redemption or otherwise; (iii) non-compliance with the affirmative and negative covenants; (iv) failure to file disclosures in the time period stipulated; and (v) certain events of bankruptcy or insolvency with respect to the Company or any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that taken together would constitute a significant subsidiary. As of December 31, 2018 and March 31, 2019, the Company was not in compliance with certain of these covenants. Although the Company failed to file its annual report on Form 10-K for the year ended December 31, 2018 in the time period stipulated in the Amended and Restated Indenture, the Company filed such report within the cure period provided under the Amended and Restated Indenture.

The commencement of the 2019 Chapter 11 Cases constituted an event of default under the Amended and Restated Indenture causing all outstanding New Notes to become due and payable immediately without further action or notice.

 

Interest is payable on the New Notes on February 15 and August 15 of each year, beginning on February 15, 2018. The New Notes will mature on February 15, 2024.

 

At any time prior to February 15, 2020, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the New Notes issued under the Amended and Restated Indenture, with an amount of cash not greater than the net cash proceeds of certain equity offerings, at a redemption price equal to 109% of the principal amount of the New Notes, together with accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% of the aggregate principal amount of the New Notes originally issued under the Amended and Restated Indenture remain outstanding after such redemption, and (ii) the redemption occurs within one hundred eighty ( 180 ) days of the equity offering.

 

On or after February 15, 2020, the New Notes will be redeemable, in whole or in part, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

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Year		Percentage
2020		106.75	%
2021		104.50	%
2022		102.25	%
2023 and thereafter		100.00	%

 

In addition, at any time prior to February 15, 2020, the Company may on any one or more occasions redeem all or a part of the New Notes at a redemption price equal to 100% of the principal amount thereof, plus the Applicable Premium (as defined in the Amended and Restated Indenture) as of, and accrued and unpaid interest, if any, to the date of redemption.

As discussed above, all amounts due under the New Notes are classified as current in the accompanying consolidated balance sheet as of December 31, 2018 .

Any efforts to enforce the Company’s obligations under the Amended and Restated Indenture are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Amended and Restated Indenture are subject to the applicable provisions of the Bankruptcy Code.

Lease Financing Obligations

On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contained an early buyout option for the Company to purchase the equipment for $16.0 million on February 10, 2019. The Company did not exercise the option. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16% .

7.    Price and Interest Rate Risk Management Activities

Commodity Derivatives

We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at December 31, 2018 .

Fixed-Price Swaps (NYMEX)

		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			—			$	—

Basis Swaps

		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

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		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

Collars

		Gas											Oil
Contract Period		MMBtu			Floor Price ($/MMBtu)				Ceiling Price ($/MMBtu)				Bbls			Floor Price ($/Bbl)				Ceiling Price ($/Bbl)
January 1, 2019 - December 31, 2019		4,125,000			$	2.60			$	3.00			575,730			$	43.81			$	54.04
January 1, 2020 - December 31, 2020		5,490,000			$	2.60			$	3.00			659,340			$	44.17			$	55.00
January 1, 2021 - December 31, 2021		1,825,000			$	2.60			$	3.07			294,536			$	55.25			$	63.76

Balance Sheet Presentation

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):

		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	)

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		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	)

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Successor Credit Facility (see Note 6 for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments was approximately $22.4 million as of December 31, 2018 . We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Successor Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.  

The change in fair value of our commodity and interest rate derivatives for the following periods (in thousands):

	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	)

8.    Fair Value Measurements

We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “ Fair Value Measurements and Disclosures”  (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets written down to fair value when they are impaired. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes acquisitions of oil and

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natural gas properties and other intangible assets and the initial measurement of asset retirement obligations. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction.

 

ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:  

Level 1		Quoted prices for identical instruments in active markets.
Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

   

  Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the Convenience Date. See Note 15, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Financing arrangements.  The carrying amounts of our bank borrowings outstanding, including the term loans, represent their approximate fair value because our current borrowing rates are variable and do not materially differ from market rates for similar bank borrowings. As of December 31, 2018 , the carrying value of our New Notes approximates its fair value. We consider the inputs to the valuation of our New Notes to be Level 2.

Derivative instruments.  As of December 31, 2018 , our commodity derivative instruments consisted of fixed-price swaps, basis swap contracts and collars. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates.

 

Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):

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		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	)

  During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.

 

Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations.  These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 9. The fair value of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging; and (4) the average inflation factor. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended December 31, 2018 (Successor), we incurred impairment charges of $29.7 million as oil and natural gas properties with a net cost basis of $116.0 million were written down to their fair value of $86.3 million . During the five months ended December 31, 2017 (Successor), we incurred impairment charges of $47.6 million as oil and natural gas properties with a net cost basis of $83.0 million were written down to their fair value of $35.4 million . In order to determine whether the carrying value of an asset is recoverable, the Company compares net capitalized costs

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of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, the Company writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future oil, natural gas and NGLs prices; and (iv) a market-based weighted average cost of capital rate. The underlying oil, natural gas and NGLs prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

 

9.    Asset Retirement Obligations

  

Upon the Company's emergence from bankruptcy on August 1, 2017, as discussed in Note 15, the Company applied fresh-start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at the Convenience Date.

The following provides a roll-forward of our asset retirement obligations (in thousands):

Asset retirement 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

⁽¹⁾ As a result of the application of fresh-start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factor of 1.8% ; and (iv) a credit-adjusted risk-free interest rate of 6.4% .

 

Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. Based on our reviews, we decreased our estimates of future asset retirement obligations by a net $4.9 million in 2018 and recorded an additional asset retirement obligation of approximately $3.6 million in 2017.

During the year ended December 31, 2018 (Successor), inputs to the valuation of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 6.5% and 7.1% ; and (4) the average inflation factor of 1.7% . These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are sensitive and subject to change.

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10.   Commitments and Contingencies

 

Transportation Demand Charges

As of December 31, 2018 , we have a contract that provides firm transportation capacity on pipeline systems. The remaining term on this contract is approximately two years and requires us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.

The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2018 . However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.

		Demand Charges
		(in thousands)
2019		$	820
2020		410
Total		$	1,230

Lease Commitments

Rent expense for our office leases was $2.2 million , $0.7 million and $1.1 million for the year ended December 31, 2018 (Successor), the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. The rent expense relates to the lease of our office space in Houston, Texas as well as office leases in our other operating areas. As of December 31, 2018 , the minimum contractual obligations were approximately $9.2 million in the aggregate. Our policy is to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease.

		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

Development Commitments

We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. As of December 31, 2018 , total estimated costs to be spent in 2019 is approximately $28.5 million of which $15.0 million and $9.0 million , relate primarily to our drilling and completion commitments in the Arkoma Basin and the Pinedale field in the Green River Basin, respectively.

Legal Proceedings

On February 1, 2017, the 2017 Debtors filed the 2017 Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the 2017 Bankruptcy Court. The 2017 Debtors’ 2017 Chapter 11 Cases were administered jointly under the caption “In re Vanguard Natural Resources, LLC, et al.” On July 18, 2017, the 2017 Bankruptcy Court entered the Confirmation Order. Consummation of the Final Plan was subject to certain conditions set forth in the Final Plan. On the Effective Date, all of the conditions were satisfied or waived and the Final Plan became effective and was implemented in accordance with its terms. The 2017 Debtors’ 2017 Chapter 11 Cases will remain pending until the final resolution of all outstanding claims.

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Pursuant to 11 U.S.C. § 362, the Predecessor’s legal proceedings were automatically stayed as to the 2017 Debtors through the Effective Date. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the 2017 Chapter 11 Cases.

Pursuant to 11 U.S.C. § 362, legal proceedings against the Company will be automatically stayed during the pendency of the 2019 Chapter 11 Cases.

We are also a party to a separate legal proceeding as further discussed below.

Litigation Relating to Vanguard’s 2015 merger with LRR Energy, L.P.

    

In June and July 2015, purported unitholders of LRR Energy, L.P. (“LRE”) filed four lawsuits challenging Vanguard’s 2015 merger with LRE (the “LRE Merger”). These lawsuits were styled (a) Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware; (b) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; (c) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District; and (d) Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division. These lawsuits have been voluntarily dismissed or nonsuited.

On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit in connection with the LRE Merger. This lawsuit is styled Robert Hurwitz v. Eric Mullins et al., Civil Action No. 1:15-cv-00711-MAK, in the United States District Court for the District of Delaware (the “LRE Lawsuit”). On June 22, 2016, the LRE Plaintiff filed his Amended Class Action Complaint (the “Amended LRE Complaint”) against LRE, the members of the board of directors of the general partner of LRE, Vanguard, Lighthouse Merger Sub, LLC, and the members of Vanguard’s board of directors (the “LRE Lawsuit Defendants”).

In the Amended LRE Complaint, the LRE Plaintiff alleges multiple causes of action under the Securities Act and Exchange Act related to the registration statement and proxy statement filed with the SEC in connection with the LRE Merger (the “LRE Proxy”). In general, the LRE Plaintiff alleges that the LRE Proxy failed, among other things, to disclose allegedly material details concerning Vanguard’s (x) debt obligations and (y) ability to maintain distributions to unitholders. Based on these allegations, the LRE Plaintiff sought, among other relief, to rescind the LRE Merger, and an award of damages, attorneys’ fees, and costs.

On January 2, 2018, the court in the LRE Lawsuit certified a class of plaintiffs that includes all persons or entities holding LRE common units as of August 28, 2015, through the close of the LRE Merger on October 5, 2015, but excluding the LRE Lawsuit Defendants and certain related persons and entities (the “LRE Class”). The window for potential members of the LRE Class to request exclusion from the LRE Class closed on May 29, 2018, with 22 LRE unitholders timely requesting exclusion.

On June 27, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff, on his own behalf and on behalf of the LRE Class, entered into a stipulation of settlement (the “Stipulation”). As amended on July 11, 2018, and on July 25, 2018, the Stipulation provided that the LRE Class settle and release all claims against the LRE Lawsuit Defendants relating to the LRE Merger, in exchange for an aggregate settlement payment of $8.0 million . Of that settlement amount, Vanguard was to contribute $0.7 million , with the remainder to be paid by the insurers of the LRE Lawsuit Defendants. The LRE Lawsuit Defendants continued to deny all allegations of liability or wrongdoing.

On July 18, 2018, the court held a hearing to consider whether to preliminarily approve the proposed settlement. In response to matters raised at that hearing, on July 25, 2018, the LRE Lawsuit Defendants and the LRE Plaintiff amended the Stipulation and submitted to the court a revised notice of proposed settlement, proof of claim and release form, and summary notice of proposed settlement. On July 26, 2018, the court entered an order preliminarily approving the settlement as set forth in the amended Stipulation.

On December 14, 2018, the court held a hearing to consider whether to finally approve the proposed settlement. Also on December 14, 2018, the court entered an order finally approving the settlement and finding that “the settlement with its two levels of consideration is fair, reasonable, and adequate to all members of the Class of Plaintiffs.” On December 19, 2018, the parties filed a Joint Motion to Amend the Judgment, asking the court to amend, in certain respects, the order finally approving the settlement. Later that day, the court granted the parties’ Joint Motion to Amend the Judgment and entered an Amended Judgment Order that clarifies, in certain respects, its initial order finally approving the settlement and instructs the clerk of court to close the case.

The case is now closed.

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We are also defendants in certain legal proceedings arising in the normal course of our business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on the Company cannot be predicted with certainty. Furthermore, our insurance may not be adequate to cover all liabilities that may arise out of claims brought against us. If one or more negative outcomes were to occur relative to these matters, the aggregate impact to our financial position, results of operations or cash flow could be material.

In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under applicable environmental laws, that could reasonably be expected to have a material adverse effect on the Company’s condensed consolidated financial position, results of operations or cash flow. 

11.  Stockholders’ Equity (Members’ Deficit)

Cancellation of Units and Issuance of Common Stock

As previously discussed, all outstanding preferred units of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% (subject to dilution) of outstanding shares of Common Stock and (ii) Preferred Unit Warrants, in full and final satisfaction of their interests. Further, all common equity of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders of the common equity received Common Unit Warrants, in full and final satisfaction of their interests. Please see further discussion below regarding the issuance of new warrants. On the Effective Date, the Company issued 20.1 million shares of Common Stock, $0.001 par value, in accordance with the Final Plan.

Warrant Agreement

 

On the Effective Date, the Company entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued: (i) to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), (B) 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and (C) 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with the Series A Preferred Units and Series B Preferred Units, the “Preferred Units”), three and a half year warrants (the “Preferred Unit Warrants”), which will be exercisable to purchase up to 621,649 shares of Common Stock as of the Effective Date; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which will be exercisable to purchase up to 640,876 shares of Common Stock as of the Effective Date. The expiration date of the Warrants is February 1, 2021. The strike price for the Preferred Unit New Warrants is $44.25 , and the strike price for the Common Unit New Warrants is $61.45 .

Management Incentive Plan

On August 22, 2017, the Company’s board of directors (the “Board”) approved, upon the recommendation of the Company’s Compensation Committee (“Committee”), the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”), which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders.

The maximum number of shares of common shares available for issuance under the MIP is 2,233,333 shares.

The MIP is administered by the Committee or, in certain instances, its designee. Employees, directors, and consultants of the Company and its subsidiaries are eligible to receive awards of stock options, restricted stock, restricted stock units (“RSUs”) or other stock-based awards at the Committee or its designee's discretion.

The Board may amend, modify, suspend, or terminate the MIP in its discretion; however, no amendment, modification, suspension or termination may materially and adversely affect any award previously granted without the consent of the participant or the permitted transferee of the award. No grant will be made under the MIP more than 10 years after its effective date.

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Earnings Per Share/Unit

Basic earnings per share/unit is computed by dividing net earnings attributable to stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units. The Company uses the treasury stock method to determine the dilutive effect.

The diluted earnings per share calculation for the year ended December 31, 2018 excluded approximately 1.3 million warrants and 301,065 RSUs that were antidilutive as we were in a loss position. The diluted earnings per share calculation excludes approximately 1.3 million warrants and 11,250 RSUs that were antidilutive for the five months ended December 31, 2017. For the seven months ended July 31, 2017, 13.5 million phantom units were excluded from the calculation of diluted earnings per unit as they were antidilutive.

12.    Share-Based Compensation

Effect of Emergence from Bankruptcy on Unit-Based Compensation

Pursuant to the Final Plan, all unvested equity grants under the Predecessor’s Long-Term Incentive Plan (the “Predecessor Incentive Plan”) that were outstanding immediately before the Effective Date were canceled and of no further force or effect as of the Effective Date. In addition, on the Effective Date, the Predecessor’s Incentive Plan was canceled and extinguished, and participants in the Predecessor’s Incentive Plan received no payment or other distribution on account of the Incentive Plan.

Management Incentive Plan

As discussed in Note 11 , “Stockholders’ Equity,” on August 22, 2017, the Company’s Board of Directors (the “Board”) approved the MIP, which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders.

MIP Restricted Stock Units

The MIP allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is expensed over the requisite service period.

In January 2018, the Company granted 78,190 time-based restricted stock unit (“RSU”) awards to executives and certain management-level employees with a grant-date fair value of $19.50 per unit and a vesting period of three years . In September 2018, the Company granted an additional 126,660 time-based RSU awards to executives and certain management-level employees with a grant-date fair value of $21.01 per unit and a vesting period of three years . The additional grants were issued as replacement awards as a result of the cancellation of certain total shareholder return (“TSR”) performance restricted stock unit awards, as further discussed below. In October 2018, an employee was granted 29,815 time-based restricted stock unit awards with a grant-date fair value of $4.97 per unit which will vest over a period of three years .

In March 2018, a director was granted 5,893 time-based restricted stock unit awards with a grant-date fair value of $11.99 per unit of which 1,474 units vested immediately and the remaining 4,419 units will vest over a period of three years . In September 2018, the Company granted an additional 36,513 time-based RSU awards to its directors with a grant-date fair value of $5.45 per unit which will vest over a period of three years .

The following table summarizes our time-based RSUs as of December 31, 2018 :

		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

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We expense time-based RSUs on a straight-line basis over the requisite service period. As of December 31, 2018 , the total remaining unearned compensation related to non-vested time-based RSUs was $3.6 million , which will be amortized over the weighted-average remaining service period of 2.0 years. The weighted average grant-date fair value of time-based RSUs granted was $19.50 during the five months ended December 31, 2017.

In January 2018, the Company granted 191,390 TSR performance RSU awards to executives and certain management-level employees. As discussed above, in September 2018, the Company canceled all unvested TSR performance restricted stock units. Immediately after the cancellation, the Company issued replacement awards consisting of 126,660 time-based RSUs and 63,330 TSR performance RSUs, assuming target performance. In October 2018, an employee was granted 5,963 TSR performance restricted stock units.

The TSR performance RSUs would vest assuming achievement of the goals at target level. Awards of TSR performance RSUs will be earned based on a predefined performance criteria determined by comparing our total shareholder return during a three -year period to the respective total shareholder returns of companies in a performance peer group. Based upon our ranking in the performance peer group, a recipient of TSR performance RSUs may earn a total award ranging from 0% to 200% of the initial grant. The TSR modifier is considered a market condition. The awards are also subject to certain other performance conditions which were considered in calculating the grant date fair value.

We estimated the fair value of TSR Performance RSUs at the modification date using a Monte Carlo simulation. Assumptions used in the Monte Carlo simulation were as follows:

		TSR Performance RSU Replacement Awards
Modification Date		September 11, 2018
Remaining Performance period		2.31 years
VNR Closing Price		$5.40
VNR Beginning TSR Price		$19.00
Compounded Risk-Free Interest Rate (2.31-yr)		2.75%
VNR Historical Volatility (2.31-yr)		71.69%
Fair value of unit		$19.76

We recognize compensation expense on a straight-line basis over the requisite service period. As of December 31, 2018 , total remaining unearned compensation related to TSR performance RSUs was $1.1 million , which will be amortized over the weighted-average remaining service period of 2.0 years.

Share-based compensation for the Predecessor and Successor periods are not comparable. Our condensed consolidated statements of operations reflect non-cash compensation related to our MIP of $2.3 million and $0.1 million for the year ended December 31, 2018 (Successor) and five months ended December 31, 2017, respectively, and non-cash compensation related to the Predecessor Incentive Plan of $5.8 million for the seven months ended July 31, 2017 (Predecessor).

13.  Income Taxes

On December 22, 2017, President Trump signed into law the Tax Act that significantly reforms the U.S. tax code. The provisions of the Tax Act that impacted us include, but are not limited to: (i) a permanent reduction of the corporate income tax rate from 35% to 21%, (ii) a limitation of the deduction for certain net operating losses to 80% of the current year taxable income, (iii) an elimination of net operating loss carryback coupled with an indefinite net operating loss carryforward, (iv) a partial limitation on the deductibility of business interest expense, and (v) immediate deductions for certain new investments.

In response to the Tax Act, the SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC Topic 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC Topic 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.

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The Company's preliminary analyses and provisional estimates of the financial statement impacts of the Tax Act were completed in accordance with guidance issued by the SEC under Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provided for a one-year period to complete the accounting for this expansive new law. At the close of the current measurement period, the company has finalized its assessment of the impact of U.S. tax reform. Management concluded that measurement period adjustments created no material impact to the Company's 2017 Consolidated Financial Statements preliminary estimates related to both the reduced corporate income tax rate and the other applicable provisions of the Tax Act.

Prior to July 31, 2017, the Predecessor was a limited liability corporation treated as a partnership for federal and state income tax purposes, in which the taxable income tax or loss of the Predecessor were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Tax benefit of $0.5 million is included in our Consolidated Statements of Operations for the seven months ended July 31, 2017 (Predecessor) as a component of Selling, general and administrative expenses.

The deferred tax effects of the Company’s transition to a C corporation are included in the period ended July 31, 2017. Since the Company’s net deferred tax asset as of July 31, 2017 was fully reserved, there was no impact to the consolidated financial statements.

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:

	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	%		—	%

Deferred income tax balances representing the tax effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities are as follows (in thousands):

	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)	$	—			$	—

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At December 31, 2018, the Company has U.S. domestic net operating loss carry forwards of approximately $73.9 million , of which $42.5 million will begin to expire in varying amounts beginning in 2035 and $31.4 million have no expiration date. In addition, the Company has state net operating loss carry forwards of approximately $34.1 million , of which $28.5 million will expire in varying amounts beginning in 2022 and $5.6 million have no expiration date.

In assessing the realizability of net deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2018, based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is not more likely than not that the Company will realize the benefits of these deductible differences.

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2018. The tax years 2017 and 2018 remains open to examination for federal and state income tax purposes.

14.    Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

 

On February 1, 2017, the 2017 Debtors filed the 2017 Chapter 11 Cases under Chapter 11 of the Bankruptcy Code in the 2017 Bankruptcy Court. The 2017 Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.”

On July 18, 2017, the 2017 Bankruptcy Court entered the Confirmation Order, which approved and confirmed the Final Plan. The Final Plan provided for the reorganization of the 2017 Debtors as a going concern and significantly reduced the long-term debt and annual interest payments of the Successor. During the pendency of the 2017 Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the 2017 Bankruptcy Court.

The 2017 Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017. The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Predecessor’s equity securities outstanding immediately before the Effective Date (including any unvested restricted units held by employees or officers of the Debtor, or options and warrants to purchase such securities) have been cancelled and are of no further force or effect as of the Effective Date. Under the Final Plan, the 2017 Debtors’ new organizational documents became effective on the Effective Date. The Successor’s new organizational documents authorize the Successor to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Final Plan on the Effective Date. In addition, on the Effective Date, the Successor entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Successor issued 20.1 million outstanding shares of common stock, $0.001 par value. (“Common Stock”).

15.    Fresh-Start Accounting

Upon the Company’s emergence from the 2017 Chapter 11 Cases, the Company qualified for and applied fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value (as defined below) of the Company’s assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 14 , “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” for the terms of the Final Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as “Successor” or “Successor Company.” However, the Company will continue to present financial information for any periods before application of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the fair value of the Successor Company’s total assets (the “Reorganization Value”) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization.

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company’s long-term debt and stockholders’ equity. The estimated Enterprise Value at the Effective Date was $1.425 billion as established in the Final Plan and approved by the 2017 Bankruptcy Court. The Enterprise Value was derived from an independent valuation using an asset based methodology of proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the Convenience Date.

The Company’s principal assets are its oil and natural gas properties. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future oil, natural gas and NGLs prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0% . The proved reserve locations were limited to wells expected to be drilled in the Company’s five -year development plan. Weighted average oil, natural gas and NGLs prices utilized in the determination of the fair value of oil and natural gas properties were $67.20 per barrel of oil, $3.69 per million British thermal units (MMBtu) of natural gas and $24.59 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees, quality differentials and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices.

In estimating the fair value of the Company's unproved acreage that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

See further discussion below under “Fresh-Start Adjustments” for the specific assumptions used in the valuation of the Company's various other assets.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of July 31, 2017 (in thousands):

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	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

The following table reconciles the Company’s Debt as of July 31, 2017 (in thousands):

	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

The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of July 31, 2017 (in thousands):

	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

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Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets and liabilities.

		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

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		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

Reorganization Adjustments:

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.

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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

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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

See Note 11 , “Stockholders’ Equity (Members’ Deficit)” for additional information on the issuances of the Successor’s equity.

Fresh-Start Adjustments:

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

In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to value the Company’s other operating assets, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market

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approach was used to value the Company’s vehicles, using recent transactions of similar assets to determine the fair value from a market participant perspective.

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).

26) Reflects the fair value adjustment to the Potato Hills gas gathering assets on the non-controlling interest.

Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to the 2017 Petition Date as a direct result of the Final Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in “Reorganization items” in the Company’s unaudited consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

	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

Subsequent to the Emergence Date, we recorded reorganization costs of $3.7 million and $6.5 million during the year ended December 31, 2018 and the five months ended December 31, 2017, respectively, primarily for legal and professional fees attributable to post restructuring activities.

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Supplemental Selected Quarterly Financial Information

 

Financial information by quarter (unaudited) is summarized below.

		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	)

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		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.

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Supplemental Oil and Natural Gas Information

 

We are an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

Capitalized costs related to oil, natural gas and NGLs producing activities and related accumulated depletion, amortization and accretion were as follows at December 31:

		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

 

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

Costs incurred in oil, natural gas and NGLs producing activities, whether capitalized or expensed, were as follows for the periods indicated (in thousands):

		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

 

No internal costs or interest expense were capitalized in 2018 or 2017 .

 

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Oil and Natural Gas Reserves (Unaudited)

Net quantities of proved developed and undeveloped reserves of oil, natural gas and NGLs and changes in these reserves during the years ended December 31, 2018 and 2017 are presented below. Estimates of proved reserves included in this Annual Report at December 31, 2018 were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. In accordance with our internal policies and procedures related to reserve estimates, annually we engage an independent petroleum engineering firm to audit properties comprising at least 80% of our reserves. For the years ended December 31, 2018 and 2017 , we engaged Miller and Lents to perform the audits.

 

		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		—			—			—

Revisions of previous estimates of reserves are a result of changes in oil and natural gas prices, production costs, well performance and the reservoir engineer’s methodology. Our reserves increased by 458.3 Bcfe during the year ended December 31, 2017 , primarily due to additions of undeveloped reserves which were classified as contingent resources as of December 31, 2016, offset by properties divested in the Permian and Williston Basins during 2017.

Our reserves decreased by 744.1 Bcfe during the year ended December 31, 2018 , due primarily to the reclassification of proved undeveloped reserves to contingent resources due to uncertainties discussed below and properties divested during 2018.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. The meaningfulness of reserve

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estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2018 .

As of December 31, 2018 , the Company has removed all proved undeveloped reserves from its total proved reserve estimate due to uncertainty regarding its ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves. The following table represents a summary of our proved undeveloped reserves activity during the year ended December 31, 2018. This activity includes updates to prior proved undeveloped reserves, and the impact of changes in economic conditions, including changes in commodity prices and the uncertainty regarding our ability to continue as a going concern.

	Bcfe
Proved Undeveloped Reserves at January 1, 2018	596.2
Divestitures	(1.0	)
Conversion to developed	(68.4	)
Proved Undeveloped Reserves reclassified to contingent resources	(526.8	)
Proved Undeveloped Reserves at December 31, 2018	—

Divestitures.  During the year ended December 31, 2018 , our proved undeveloped reserves decreased due to divestiture of oil and gas properties including 1.0 Bcfe of our total proved undeveloped reserves booked as of December 31, 2017.

Conversions. During the year ended December 31, 2018 , we developed approximately 68.4 Bcfe of our total proved undeveloped reserves booked as of December 31, 2017 through the drilling of 142 gross (34.1 net) wells. 

Revisions/Reclassifications: At December 31, 2018 , we reclassified 526.8 Bcfe of proved undeveloped reserves to the contingent resource category. Contingent resources are resources that are potentially recoverable, but not yet considered mature enough for development due to technological or capital restraints. Because substantial doubt exists about our ability to continue as a going concern, in determining year-end 2018 reserves amounts, we concluded we lacked the required degree of certainty about our ability to fund a development drilling program and the availability of capital resources that would be required to develop proved undeveloped reserves. As a result of our inability to meet the reasonable certainty criteria for recording these proved undeveloped reserves as prescribed by the SEC, we did not record any proved undeveloped locations in the December 31, 2018 reserve report.

Development Plans.  This year, because substantial doubt exists about our ability to continue as a going concern, we no longer expect to develop our proved undeveloped reserves within five years of initial booking, due to uncertainty that we have the ability to fund a development plan. Therefore, as of December 31, 2018, we reclassified all of our proved undeveloped reserves to contingent resources.

Results of operations from producing activities were as follows for the periods indicated:

		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

 

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(1)	Production cost includes lease operating expenses, transportation, gathering, processing and compression

fees, and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at December 31 is as follows:

		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.

For the December 31, 2018 and 2017 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil and natural gas price based upon the 12-month average price of $65.66 and $51.22 per barrel of crude oil, respectively, $3.10 and $2.99 per MMBtu for natural gas, respectively, adjusted for quality, transportation fees and a regional price differential, and the volume-weighted average price of $26.57 and $19.24 per barrel of NGLs. The NGLs prices were calculated using the differentials for each property to a West Texas Intermediate reference price of $65.66 and $51.22 for the years ended December 31, 2018 and 2017 , respectively. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

The following are the principal sources of change in our standardized measure of discounted future net cash flows:

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		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.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

ITEM 9A.    CONTROLS AND PROCEDURES

 

(a)	Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2018 .

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2018 , is set forth in Item 9A(b) below.

 

(b)	Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting, as defined by SEC rules adopted under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. It consists of policies and procedures that:

•	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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2018 . In making this assessment, we used the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2018 . 

(c)	Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B.    OTHER INFORMATION

 

None.

PART III

 

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Board of Directors

The Board of Directors of the Company (the “Board”) consists of seven members.

The following sets forth information concerning each member of the Board as of April 15, 2019 , including each director’s name, age, principal occupation or employment for at least the past five years and the period for which he has served as a director of the Company. Each director’s initial term will expire at the annual meeting of stockholders. There are no family relationships among any of our directors or executive officers or arrangements.

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

R. Scott Sloan has served as our President and Chief Executive Officer since January 2018 and as a director since August 2017. Prior to his appointment as President and Chief Executive Officer, Mr. Sloan had served as our Executive Vice President and Chief Financial Officer since September 26, 2017 and was a member of the Compensation Committee of the Board and the Chairman of the Audit Committee of the Board from the Effective Date until September 26, 2017. From 2015 to 2016, Mr. Sloan served as Senior Vice President, Strategy, Commercial and Global New Business Development at Hess Corporation, where he oversaw strategic planning, new business development, and oil and gas marketing. Prior to 2015, Mr. Sloan served in various senior leadership positions throughout a 25 year career at BP, including as President of BP Russia from 2012 through 2014 and as Chief Financial Officer of BP Russia from 2009 through 2012. While at BP, Mr. Sloan also served as Director of Mergers and Acquisitions and in several regional Chief Financial Officer roles. Mr. Sloan has also held board positions with TNK Holdings, Slavneft, Rusia Petroleum, In Salah Sales, and Medgaz. He holds a B.A. in Economics from Colgate University and M.B.A. in Corporate Finance from the University of Chicago. Mr. Sloan’s extensive background in the energy industry and his financial background provides him with valuable experience on which he can draw while serving as a member of the Board.

Randall Albert has served as a director since September 2017. Mr. Albert is the President and Chief Executive Officer of Shale Advisory Group, LLC. Mr. Albert founded Shale Advisory Group, LLC in 2013, after retiring from CONSOL Energy Inc. (“CONSOL”) in January 2014, where he had served as Chief Operating Officer - Gas since 2010. During his time at CONSOL, Mr. Albert led the rapid development of CONSOL’s Marcellus Shale and emerging Utica Shale programs. Mr. Albert has served in various senior leadership positions in the energy sector throughout his 34 year career. Mr. Albert also currently serves on the board of directors of Montage Resources, a non-executive board member at Wellsite Fishing & Rental Services, LLC, and as a member of the advisory board of Black Bay Energy Capital. Since January 2018, Mr. Albert has served on the advisory board of Gas Field Services, LLC, an Appalachian based service provider. Mr. Albert previously served as the chairman of the Marcellus Shale Coalition and was a member of the Virginia Tech Mining and Minerals Engineering Advisory Board. Mr. Albert holds a B.S. in Mining Engineering from Virginia Tech, where in 2016 he was inducted into the Virginia Tech Academy of Engineering Excellence, the highest honor bestowed on College of Engineering graduates. Mr. Albert’s decades long experience in the energy industry makes him well qualified to serve on the Board.

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Patrick J. Bartels, Jr. has served as a director since February 2019. Mr. Bartels is a senior investment professional with 20 years of experience and currently serves as the Managing Member of Redan Advisors LLC. His professional experience includes investing in complex financial restructurings and process intensive situations in North America, Asia and Europe in a broad universe of industries. Mr. Bartels has led creditors’ committees and served as a director on numerous public and private boards of directors with an extensive track-record of driving value added returns for all stakeholders through governance, incentive alignment, capital markets transactions and mergers and acquisitions. Mr. Bartels currently serves on the board of directors of Arch Coal, Inc., Sungard Availability Services, LifeCare Holdings, Tuscany International Drilling and Payless Holdings, LLC. Mr. Bartels also served on the board of directors of WCI Communities, Inc. and TOUSA Liquidation Trust. Mr. Bartels was previously a Managing Principal of Monarch Alternative Capital LP in New York, a private investment firm that focuses primarily on distressed companies. Prior to joining Monarch Alternative Capital LP, Mr. Bartels was a high-yield investments analyst at Invesco Ltd. He began his career at PricewaterhouseCoopers LLP, where he was a Certified Public Accountant. Mr. Bartels received a Bachelor of Science in Accounting with a concentration in Finance from Bucknell University. He also holds the Chartered Financial Analyst designation.

W. Greg Dunlevy has served as a director since October 2017 and as the Chairman of the Board since December 2018. In 2015, Mr. Dunlevy retired from Kosmos Energy Ltd. (“Kosmos”), where he was one of the Founding Partners. Mr. Dunlevy joined Kosmos in 2003 and served in a variety of senior leadership roles, including Executive Vice President and Chief Financial Officer. Prior to Kosmos, Mr. Dunlevy served as Vice President of Finance and Administration for the Triton Energy Ltd. business unit of Amerada Hess Corporation (now Hess Corporation) following its acquisition of Triton, where he was Senior Vice President and Chief Financial Officer. Mr. Dunlevy began his career with ARCO, where he served in a variety of positions including for ARCO Petroleum Products Company, the ARCO Oil and Gas Company, and Lyondell Petrochemical Company subsidiaries. Mr. Dunlevy currently serves as an advisor to and on the board of Mexico City based Citla Energy. Mr. Dunlevy holds a B.S. in Chemistry from the College of William & Mary and an M.B.A. from Harvard Business School. Mr. Dunlevy’s extensive energy industry and financial background bring important experience and skill to the Board.

Joseph Hurliman Jr. has served as a director since February 2018. Mr. Hurliman served as the President and Chief Executive Officer of Discovery Natural Resources LLC, a private upstream oil and gas company (“Discovery”). Mr. Hurliman also served as a board advisor to FIML Natural Resources, LLC, the predecessor company of Discovery. In 2012, Mr. Hurliman founded Hurliman Enterprises LLC, an oil and gas consultancy firm. Mr. Hurliman brings over 35 years of exploration & development experience to the Board. Prior to Discovery, Mr. Hurliman held a variety of roles in BP and its JV partnerships, with over 30 years in North and South America, the UK and Russia. He held a number of senior positions in reservoir and asset management on some of BP’s largest projects. Mr. Hurliman holds a B.A. in Chemistry from Whitman College and B.S. in Chemical Engineering from The California Institute of Technology. Mr. Hurliman brings to the Board his expertise in exploration appraisal and field development, production operations and oil and gas reserves management.

Andrew E. Schultz has served as a director since February 2019. Mr. Schultz is a managing member of Woodbine Consulting, LLC and a member of Holding Capital Group, a private equity firm, with a varied career combining an operational, legal and financial background. His past professional experience includes being a founder and CEO of Radiology Billing Associates, a third party medical billing and transcription business, an associate attorney at Cummings & Lockwood, concentrating in healthcare and general corporate matters, and a vice-president and general counsel of Greenwich Hospital. Mr. Schultz has extensive experience serving on boards of directors and has served as board chairman or director on numerous public and private boards of directors with an extensive track-record of driving value added returns for all stakeholders through governance, incentive alignment, capital markets transactions and mergers and acquisitions. Mr. Schultz currently serves on the board of directors of Algoma Steel, Inc., BBK Worldwide, LLC, Innovative Fixture Solutions, LLC (where he chairs the audit committee), Legacy Cabinets, Inc. (where he chairs the board of directors), Mori Lee, LLC, Physician’s Weekly, LLC (where he is the board executive chairman), School Specialty, Inc. (where he chairs the audit committee), and Sierra Hamilton, LLC (where he chairs the compensation committee). Mr. Schultz previously served on the board of directors of Western Kentucky Coal Resources, LLC, TEN: The Enthusiast Network (formerly, Source Interlink Companies, Inc.), Bankruptcy Management

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Solutions, Inc., and PSI, LLC. Mr. Schultz holds a Bachelor of Arts in Economics and in Geography from Clark University and a Juris Doctor from Fordham University School of Law.

L. Spencer Wells has served as a director since February 2019. Mr. Wells is a Founding Partner of Drivetrain Advisors, LLC, a firm that provides fiduciary services, including board of director representation and creditor advisory and trustee services to the alternative investment industry. Prior to founding Drivetrain Advisors, Mr. Wells was a Partner and Senior Advisor at TPG Special Situations Partners where he was a senior member of a team of investment professionals managing a multi-billion dollar portfolio of distressed credit investments across several industries, including oil and gas, real estate, gaming and industrials. Mr. Wells has extensive experience servicing on the board of directors and currently serves on several boards, including Telford Offshore Holdings Ltd (fka Sea Trucks) (where he chairs the audit committee), NextDecade Corp. (where he chairs the audit committee), Samson Resouces II, LLC (including its compensation and audit committees), Vantage Drilling International, Town Sports International Holdings, Inc. (where he chairs the nominating and governance committee and is a member of the audit committees), Jones Energy Inc. and Advanced Emissions Solutions, Inc. (where he chairs the board of directors and is a member of the finance committee). Mr. Wells previously served on the board of directors of Preferred Proppants LLC (through January 2018), Roust Corporation (through December 2017), Lily Robotics. Inc. (through September 2017), Affinion Group, Inc. (through July 2017), Syncora Holdings Ltd. (through December 2016), Global Geophysical Services, LLC (through October 2016), Navig8 Crude, Ltd. (through May 2015) and CertusHoldings. Inc. and CertusBank, N.A. (through April 2016). Mr. Wells is also a member of the board of trustees of Western Reserve Academy. Mr. Wells holds a Master of Business Administration from the Columbia Business School and a Bachelor of Arts, Psychology from Wesleyan University.

Corporate Governance

We maintain on our website, www.vnrenergy.com, copies of the charters of each of the committees of the Board, as well as copies of our Corporate Governance Guidelines; Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer; Insider Trading Policy; Code of Business Conduct and Ethics; and Related Party Transactions Policy. Copies of these documents are also available in print upon request of our Corporate Secretary. The Code of Business Conduct and Ethics provides guidance on a wide range of conduct, conflicts of interest and legal compliance issues for all of our directors, officers and employees. The Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer is designed to deter wrongdoing and promote ethical conduct, timely and accurate reporting, and compliance with laws. We will post any amendments to, or waivers of, the Code of Business Conduct and Ethics or Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer on our website located at www.vnrenergy.com as required by applicable rules.

Board Leadership Structure and Role in Risk Oversight

Mr. Dunlevy, one of our independent directors, currently serves as Chairman of the Board. The Corporate Governance Guidelines adopted by the Board provide that the independent directors will meet in executive session at least twice per year, or more frequently if necessary. As Chairman of the Board, Mr. Dunlevy serves as lead independent director and chairs any non-management executive sessions of the Board.

Committees of the Board of Directors

The standing committees of the Board currently are the audit committee (the “Audit Committee”), the compensation committee (the “Compensation Committee”), the nominating and corporate governance committee (the “N&G Committee”) and the health, safety and environmental committee (“HSE Committee”).

Audit Committee

The primary responsibilities for the Audit Committee are set forth in the Audit Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The Audit Committee’s duties include assisting the Board in fulfilling its responsibility to oversee management regarding: (i) the conduct and integrity

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of our financial reporting to any governmental or regulatory body, the public or other users thereof; (ii) our systems of internal accounting and financial and disclosure controls; (iii) the qualifications, engagement, compensation, independence and performance of our independent auditors, their conduct of the annual audit, and their engagement for any other services; (iv) our legal and regulatory compliance; and (v) our codes of ethics as established by management and the Board.

In discharging its oversight role, the Audit Committee is authorized: (i) to investigate any matter that the Audit Committee deems appropriate, with access to all of our books, records, facilities and personnel; and (ii) to retain independent counsel, auditors or other experts.

The current members of the Audit Committee are Messrs. Bartels, Dunlevy and Wells. Mr. Dunlevy is the Chairman of the Audit Committee and has been determined by the Board to be an “audit committee financial expert,” as defined by Item 407(d) of Regulation S-K (17 C.F.R. 240.407(d)). Although our Common Stock and warrants are no longer quoted on the OTCQX U.S. tier, the Board has determined each member of the Audit Committee is an independent director under the OTCQX requirements, as set forth in Part III, Item 13 of this Annual Report.

Compensation Committee

The primary responsibilities for the Compensation Committee are set forth in the Compensation Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The Compensation Committee determines and approves, either on its own or with our independent directors, compensation of the Chief Executive Officer and assists the Board in: (i) determining appropriate compensation levels for our other executive officers; (ii) evaluating officer and director compensation plans, policies and programs; and (iii) reviewing compensation and benefit plans for officers and employees.

In discharging its role, the Compensation Committee is empowered to investigate any matter brought to its attention with access to all of our books, records, facilities and personnel. The Compensation Committee may, in its sole discretion, select, retain or obtain the advice of independent legal counsel, compensation consultants or other advisors (collectively, “Advisors”) and will receive appropriate funding from us, as determined by the Compensation Committee, for payment of reasonable compensation to such Advisors. The Compensation Committee will be directly responsible for the appointment, compensation and oversight of the work of any Advisor retained by the Compensation Committee, who shall be accountable ultimately to the Compensation Committee. Prior to selecting an Advisor, the Compensation Committee shall assess the Advisor’s independence from our management, taking into consideration all relevant factors the Compensation Committee deems appropriate to such Advisor’s independence, including any factors specified in applicable rules and regulations. The Compensation Committee may select or receive advice from any Advisor it prefers, including Advisors that are not independent, after considering the independence factors required by applicable rules and regulations.

The current members of the Compensation Committee are Messrs. Albert, Hurliman and Schultz. Mr. Albert is the Chairman of the Compensation Committee.

Nominating and Corporate Governance Committee

The primary responsibilities for the N&G Committee are set forth in the N&G Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The purpose of the N&G Committee is to assist the Board by: (i) identifying, screening and reviewing individuals qualified to serve as directors and recommending to the Board candidates for election at the annual meeting of stockholders to fill Board vacancies; (ii) developing, recommending to the Board and overseeing implementation of our Corporate Governance Guidelines and Principles; and (iii) reviewing, on a regular basis, our overall corporate governance and recommending to the Board improvements when necessary.

In discharging its role, the N&G Committee is empowered to investigate any matter brought to its attention with access to all of our books, records, facilities and personnel. The N&G Committee has the power to retain outside counsel, director search

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and recruitment consultants or other experts. The N&G Committee shall have the sole authority to retain, compensate, terminate and oversee director search and recruitment consultants, who shall be accountable ultimately to the N&G Committee.

The current members of the N&G Committee are Messrs. Bartels, Sloan and Wells. Mr. Bartels is the Chairman of the N&G Committee.

Health, Safety and Environmental Committee

The primary responsibilities for the HSE Committee are set forth in the HSE Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The purpose of the HSE Committee is to assist the Board with its responsibilities relating to oversight of our health, safety and environmental practices and to monitor management’s efforts in creating a culture of safety and environmental protection. The HSE Committee primarily fulfills this responsibility by carrying out activities such as the following: (i) reviewing and monitoring safety and environmental protection practices and performance; (ii) assisting the Board with our risk management process and our security processes; (iii) developing annual health, safety and environmental goals and objectives; (iv) reviewing and providing input on the management of current and emerging health, safety and environmental issues; and (v) reviewing and monitoring significant regulatory audits, findings, orders, reports and/or recommendations issued by or to us related to health, safety and environmental matters.

The current members of the HSE Committee are Messrs. Albert, Hurliman and Sloan. Mr. Hurliman is the Chairman of the HSE Committee.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, requires our directors and executive officers, and persons who beneficially own more than 10% of a registered class of our equity securities, to file initial reports of ownership of our equity securities and reports of changes in ownership of our equity securities with the SEC. Such persons are also required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that during the fiscal year ended December 31, 2018, all Section 16(a) reporting persons complied with all applicable filing requirements in a timely manner.

Executive Officers

Certain information concerning the Company’s executive officers as of the date of this Annual Report is set forth below.

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 has served as our Chief Executive Officer since January 2018. Please read his biographical information and his experience under “Board of Directors” included under Part III, Item 10 of this Annual Report.

Ryan Midgett has served as our Chief Financial Officer since January 2018. Mr. Midgett has over a decade of experience in financial management, analysis and reporting roles in the oil and gas industry. Prior to his appointment as the Company’s Chief Financial Officer, Mr. Midgett served as the Vice President, Finance and Treasurer of the Company since August 2016. In that role, his responsibilities included strategic planning, budgeting and forecasting, economic analysis of the Company’s organic opportunities and mergers and acquisitions transactions, overseeing and executing numerous capital markets transactions, negotiating credit agreements, overseeing the Company’s insurance and risk management program, and overseeing other corporate treasury functions. Previously, he was the Company’s Treasurer since 2013 and Assistant Treasurer since April 2011. Prior to joining the Company, Mr. Midgett served in various financial analyst, investor relations, and business

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development roles at Linn Energy from 2006 to 2011. Mr. Midgett received his B.A. in Economics, Managerial Studies and Political Science from Rice University.

Jonathan C. Curth has served as our General Counsel, Corporate Secretary, Compliance Officer and Vice President of Land since December 2017. From August 2013 through December 2017, Mr. Curth served as the Assistant General Counsel at Newfield Exploration Company, where he managed upstream and midstream transactions and litigation and supported numerous departments, including land, land administration, marketing, operations, records, accounting, governmental affairs, and internal audit. Mr. Curth concentrated on domestic and international oil and gas transactions and operational matters at Baker & McKenzie LLP from 2011 through 2013 and at Brown & Fortunato, P.C. from August 2007 through January 2011. Mr. Curth brings over a decade of legal experience to us, with an emphasis on oil and gas transactions, in addition to experience in corporate governance matters and formulating and implementing land-related processes and procedures. He received his B.A. from Baylor University and his J.D. from The University of Texas School of Law. Mr. Curth is licensed in Texas and Oklahoma, has presented at several conferences and contributed to numerous articles and presentations, and he is Board Certified in Oil, Gas and Mineral Law by the Texas Board of Legal Specialization.

ITEM 11.     EXECUTIVE COMPENSATION

 

Named Executive Officers

This executive compensation section provides information about our compensation objectives and policies for our named executive officers. Pursuant to the SEC rules applicable to smaller reporting companies we must provide disclosure regarding the following individuals: (i) all individuals serving as the Company’s principal executive officer or acting in a similar capacity during the last completed fiscal year; (ii) the Company’s two most highly compensated executive officers other than the principal executive officer who were serving as executive officers at the end of the last completed fiscal year; and (iii) up to two additional individuals for whom disclosure would have been provided pursuant to clause (ii) above but for the fact that the individual was not serving as an executive officer of the Company at the end of the last completed fiscal year. We refer to these executive officers in this section and the related compensation tables as the “named executive officers.” For the fiscal year ended December 31, 2018, the named executive officers were:

•	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.

2018 Summary Compensation Table

The following table sets forth certain information with respect to the compensation paid to our named executive officers for the fiscal years ended December 31, 2018 and December 31, 2017.

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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.

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(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.

Narrative Disclosure to Summary Compensation Table

Certain terms of our named executive officers’ compensation are governed by employment agreements. We believe that these employment agreements assist us in attracting and retaining talented and dedicated executives by clearly setting forth the terms of employment and providing certainty to both parties. We maintain employment agreements with our named executive officers to ensure they will perform their roles for an extended period of time. These agreements include provisions for payments at, following or in connection with a change in control or resignation, retirement or other termination.

Post-Emergence Employment Agreements

On the Effective Date, the Company entered into amended and restated employment agreements (the “Post-Emergence Employment Agreements”) with each of Messrs. Smith and Pence (each, a “Post-Emergence Executive” and collectively, the “Post-Emergence Executives”). The Post-Emergence Employment Agreements were effective on the Effective Date and superseded the prior agreements with the Post-Emergence Executives. Mr. Smith stepped down from his position as President and Chief Executive Officer on January 15, 2018, while remaining with the Company to assist in the transition of his role until February 16, 2018. Under the terms of his Post-Emergence Employment Agreement, Mr. Smith received a lump sum severance payment of $1,750,000, which reflected Mr. Smith’s base salary for a period of 30 months. Mr. Pence agreed on January 17, 2018, that he would resign from the Company effective on or before June 29, 2018, or such other time as mutually agreed with the Company (the period of Mr. Pence’s continued employment, the “Transition Period”). Mr. Pence continued to receive his then current annual base salary during the Transition Period and received a pro-rated portion of his target annual bonus for his service during 2018. The Transition Period ended on June 29, 2018. Under the terms of his Post-Emergence Employment Agreement, Mr. Pence received a lump sum severance payment of $1,400,000, which reflected Mr. Pence’s base salary for a period of 30 months.

Vanguard Natural Resources, Inc. 2017 Management Incentive Plan

On August 22, 2017, the Compensation Committee recommended the approval of, and the Board approved, the MIP to assist the Company in attracting, motivating and retaining key personnel and to align the interests of participants with those of stockholders. The maximum number of shares of Common Stock available for issuance under the MIP is 2,233,333 shares. Employees, directors, and consultants of the Company and its subsidiaries are eligible to receive awards of stock options, restricted stock, restricted stock units or other stock-based awards at the discretion of the Compensation Committee or its designee.

On January 17, 2018, the Board approved the initial long-term incentive program under the MIP (the “LTIP”) and granted time-based restricted stock unit awards to certain Company executives (the “Initial Time RSUs”). The Initial Time RSUs generally vest in 1/3 installments on each of the first three anniversaries of October 30, 2017. On September 11, 2018, as part of the Board’s ongoing review of its compensation practices, the Board granted executives additional time-vesting restricted stock units that generally vest in full on December 31, 2020 (“Cliff RSUs”), as well as performance-based restricted stock units that are eligible to vest based on the Company’s total shareholder return relative to an index of its peers during the period from January 1, 2018 through December 31, 2020 or upon achievement of a certain share price at the end of the performance period (the “PSUs”).

Sloan Employment Agreement

Mr. Sloan was a party to an Employment Agreement with the Company dated January 17, 2018 (the “Sloan Employment Agreement”). The initial term of the Sloan Employment Agreement originally was set to end on December 31, 2020, with a subsequent 12-month term extension automatically commencing on January 1, 2021 and expiring on January 1, 2022, provided that neither the Company nor Mr. Sloan delivers a timely non‑renewal notice prior to the expiration date.

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The Sloan Employment Agreement provides that Mr. Sloan is entitled to an annual base salary of $700,000. In addition, the Board has the discretion to increase Mr. Sloan’s base salary, at any time if it deems an increase is warranted. Subject to certain terms and conditions, the Board may not reduce Mr. Sloan’s base salary without his prior written approval.

Mr. Sloan is eligible to receive an annual performance-based cash bonus award in an amount to be determined by the Board or Compensation Committee and equal to no less than 100% of his base salary. With respect to his employment in 2017, Mr. Sloan was entitled to receive an annual bonus in an amount not less than $127,500, payable on or before March 15, 2018. Mr. Sloan is also eligible to participate in the MIP in accordance with the terms determined by the Board. Furthermore, Mr. Sloan is eligible to participate in the benefit programs generally available to senior executives of the Company.

In the event of the Company’s Change in Control (as defined in the Sloan Employment Agreement), Mr. Sloan is entitled to certain change in control payments and benefits under the Sloan Employment Agreement. If, during the twelve (12) months immediately following the occurrence of a Change of Control of the Company, Mr. Sloan is terminated by the Company without Cause or resigns for Good Reason (each as defined in the Sloan Employment Agreement), Mr. Sloan will be entitled to receive within ten (10) business days after the date of his termination, (i) accrued compensation and reimbursements listed in the Sloan Employment Agreement; (ii) on the sixtieth (60th) day following the date of termination, a lump sum payment of an amount equaling two (2) times his then-current base-salary and annual bonus; (iii) immediate vesting of any unvested awards under the MIP (assuming achievement at target for any performance-based awards); (iv) any Earned but Unpaid Bonus; and (v) the Pro Rata Bonus (each as defined in the Sloan Employment Agreement). However, notwithstanding (i) through (v), if a Change of Control occurred during 2018, the payment to Mr. Sloan described in clause (ii) above would have been two (2) times the sum of his base salary and target bonus for 2018 (the “Change of Control Bonus Protection”).

Under the Sloan Employment Agreement, Mr. Sloan is entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by the Company without Cause or termination by Mr. Sloan for Good Reason (each as defined in the Sloan Employment Agreement) (and except with respect to a Change of Control, as described above), he is entitled to receive on the sixtieth (60th) day following the date of termination, a lump sum payment of (i) an amount equal to two and a half (2.5) times his then-current base salary; (ii) the Earned but Unpaid Bonus; and (iii) the Pro Rata Bonus (collectively, the “Non CIC Severance”). Upon his termination by reason of Disability (as defined in the Sloan Employment Agreement) or death, Mr. Sloan is entitled to accrued compensation, his Earned but Unpaid Bonus, and reimbursements. As a condition to receiving any of the Change of Control or severance payments and benefits provided in the Sloan Employment Agreement, Mr. Sloan (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

The Sloan Employment Agreement contains standard non-competition, non-solicitation and confidentiality provisions.

The Sloan Employment Agreement was amended and restated on January 22, 2019 (the “Amended and Restated Sloan Agreement”). The Amended and Restated Sloan Agreement is generally consistent with the Sloan Employment Agreement. The Amended and Restated Sloan Agreement becomes effective one day after the date that Mr. Sloan receives the 2019 Bonus (as defined therein). The Amended and Restated Sloan Agreement is updated to reflect Mr. Sloan’s annual base salary of $720,000 and to extend the Change of Control Bonus Protection through the end of 2020. The Amended and Restated Sloan Agreement also sets forth the terms and conditions and performance objections for Mr. Sloan’s 2019 Annual Bonus. Further, the Amended and Restated Sloan Agreement provides for Mr. Sloan to receive a $1,000,000 bonus payable in a lump sum on January 22, 2019, provided that Mr. Sloan must repay the after tax value of the bonus in connection with certain terminations incurred prior to December 31, 2019. Additionally, the Amended and Restated Sloan Agreement provides for Mr. Sloan to receive the Pro Rata Bonus if his employment is terminated as a result of his death or Disability. The Amended and Restated Sloan Agreement clarifies that the filing of a voluntary or involuntary petition by or against the Company under Chapter 11 of Title 11 of the U.S. Code will not constitute a Change of Control or a Good Reason Event. Finally, the Amended and Restated Sloan Agreement provides for Mr. Sloan to receive the Non CIC Severance in the event that he receives a non-renewal notice from the Company and his employment is not renewed.

The foregoing descriptions of the Sloan Employment Agreement and Amended and Restated Sloan Employment Agreement do not purport to be complete and are qualified in their entirety by reference to the full text of the applicable agreement.

Other Executive Employment Agreements

The Company was also party to an employment agreement with each of Ryan Midgett and Jonathan C. Curth dated January 17, 2018 and December 4, 2017, respectively (the “Other Employment Agreements”). The Other Employment Agreements each had an initial term ending on December 31, 2020, with a subsequent 12-month term extension automatically commencing on January 1, 2021 and expiring on January 1, 2022, provided that neither the Company nor the applicable executive delivers a

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timely non‑renewal notice prior to the expiration date. The Other Employment Agreements provide that Messrs. Midgett and Curth are entitled to an annual base salary of $300,000 and $305,000, respectively. In addition, the Board has the discretion to increase each executive’s base salary, at any time if it deems an increase is warranted. Subject to certain terms and conditions, the Board may not reduce either executive’s base salary without his prior written approval.

The executives are eligible to receive an annual performance-based cash bonus award in an amount to be determined by the Board or Compensation Committee. The executives are also eligible to participate in the MIP in accordance with the terms determined by the Board. Furthermore, the executives are eligible to participate in the benefit programs generally available to senior executives of the Company.

In the event of the Company’s Change in Control (as defined in the Other Employment Agreements), the executives are entitled to certain change in control payments and benefits under the Other Employment Agreements. If, during the twelve (12) months immediately following the occurrence of a Change of Control of the Company, the executive is terminated by the Company without Cause or resigns for Good Reason (each as defined in the Other Employment Agreements), the applicable executive will be entitled to receive (i) within ten (10) business days after the date of his termination, accrued compensation and reimbursements listed in the Other Employment Agreements and (ii) on the sixtieth (60th) day following the date of termination, a lump sum payment of an amount equaling two (2) times the sum of his then-current base-salary and annual bonus paid or payable with respect to the year preceding the year that the Change of Control occurs. However, notwithstanding the foregoing, if a Change of Control occurred during 2018, the payment to the applicable executive described in clause (ii) above would have been two (2) times the sum of his base salary and target bonus for 2018 (the “Other Change of Control Bonus Protection”).

Under the Other Employment Agreements, the executives are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by the Company without Cause or termination by the executive for Good Reason (each as defined in the Other Employment Agreements) (and except with respect to a Change of Control, as described above), the executive is entitled to receive (i) within ten (10) business days after the date of his termination, accrued compensation and reimbursements listed in the Other Employment Agreements and (ii) on the sixtieth (60th) day following the date of termination, a lump sum payment of an amount equal to two (2) times his then-current base salary (the “Other Non CIC Severance”). As a condition to receiving any of the Change of Control or severance payments and benefits provided in the Other Employment Agreements, the executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

The Other Employment Agreements contain standard non-competition, non-solicitation and confidentiality provisions.

The Other Employment Agreements were amended and restated on January 22, 2019 (the “Amended and Restated Other Agreements”). The Amended and Restated Other Agreements become effective on the date that the applicable executive receives his 2019 Bonus (as defined in the Amended and Restated Other Agreements). The Amended and Restated Other Agreements are generally consistent with the Other Employment Agreements, except that they include certain changes to conform them to the Amended and Restated Sloan Agreement. The agreements reflect Mr. Midgett’s and Mr. Curth’s current base salaries, $325,000 and $380,000, respectively, and provide for a target annual bonus opportunity of no less than 80% of base salary. The Amended and Restated Other Agreements also set forth the terms and conditions and performance objectives for the applicable executive’s 2019 Annual Bonus. Further, the Amended and Restated Other Agreements provide for the Messrs. Midgett and Curth to receive a bonus ($325,000 and $380,000, respectively) payable in a lump sum on January 22, 2019, provided that the applicable executive must repay the after tax value of the bonus in connection with certain terminations incurred prior to December 31, 2019. Further, the Amended and Restated Other Agreements provide for the applicable executive to receive (i) any Earned but Unpaid Bonus; and (ii) the Pro Rata Bonus (each as defined in the Other Amended and Restated Employment Agreements) upon a termination of his employment without Cause or as a result of his death or Disability or upon his resignation for Good Reason. The Amended and Restated Other Agreements also extend the Other Change of Control Bonus Protection through the end of 2020 and clarify that the filing of a voluntary or involuntary petition by or against the Company under Chapter 11 of Title 11 of the U.S. Code will not constitute a Change of Control or a Good Reason Event. Finally, the Amended and Restated Other Agreements provide for the applicable executive to receive the Other Non CIC Severance in the event that he receives a non-renewal notice from the Company and his employment is not renewed.

The foregoing descriptions of the Other Employment Agreements and the Amended and Restated Other Agreements do not purport to be complete and are qualified in their entirety by reference to the full text of the applicable agreement.

Retirement Benefits

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The Company offers its employees participation in a tax qualified defined contribution retirement plan in which each of our named executive officers participated during 2018.  The 401(k) Plan allows eligible employees to defer a portion of their eligible compensation, and such participants receive matching contributions of 100% on up to 6% of eligible compensation deferred. 

Outstanding Equity Awards at December 31, 2018

The following table provides the number and value of outstanding equity awards held by our named executive officers as of December 31, 2018. None of our named executive officers held any stock options as of such date:

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)	—		$	—		—		$	—

(1)      On the Effective Date, in connection with the Company’s emergence from the 2017 Chapter 11 Cases, all of the Predecessor’s equity previously issued to Messrs. Smith and Pence was canceled.

(2) Subject to the executive’s continued employment, for Messrs. Sloan, Midgett, and Curth, approximately 25,641, 10,684, and 3,418, respectively, of these RSUs will vest on October 30, 2019 and October 30, 2020. Subject to the executive’s continued employment, the remaining RSUs will vest in full on December 31, 2020.

(3) The number of shares reported in this column is based on achievement of target performance goals. These awards will vest subject to achievement of relative TSR or stock price performance targets for the period from January 1, 2018 through December 31, 2020.

Director Compensation

In 2018, we used a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on the Board. In setting independent director compensation, we consider the significant amount of time that directors expend in fulfilling their duties to us, as well as the skill-level required by us of members of the Board. Generally, our non-employee directors were eligible to receive the following for 2018 service: (i) an annual cash retainer of $100,000, which was paid quarterly in arrears and (ii) an annual equity grant of restricted stock units with a $100,000 grant date value. Mr. Dunlevy receives an additional annual cash retainer of $25,000 for his service as Chairman of the Audit Committee and Mr. Albert receives an additional annual cash retainer of $10,000 for his service as Chairman of the Compensation Committee. The initial 2018 grants made to directors in connection with their appointment to the Board vest 25% immediately, with the remainder vesting ratably on the first three anniversaries of the grant date. In order to transition to a uniform annual grant cycle for the non-fund-designated director’s annual equity retainers (intended to follow the Company’s annual meeting), on September 11, 2018, Messrs. Dunlevy, Albert, and Hurliman received pro-rated grants of 13,840, 14,832, and 7,841 restricted stock units, respectively, that vest on the first three anniversaries of the grant date (the “Transition Grants”). The number of restricted stock units underlying each Transition Grant was determined by calculating a pro-rated grant date value for the Transition Grant based on the number of days between the first anniversary of the applicable director’s start date and August 6, 2019 (the date that future grants are intended to be made on or following) and dividing such value by a share price of $5.80.

 

For certain former non-employee directors, specifically Messrs. Alexander, Morris and Mr. Citarrella, the director’s compensation is paid to the fund that employed such individual (i.e., Marathon, Contrarian, and Monarch, respectively) and the Board has approved that such director’s equity compensation be paid in cash in lieu of equity on the dates that such grants would have otherwise vested.

Each member of the Board is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or committees. We maintain a D&O insurance policy for the benefit of the Board and provide indemnification pursuant to our standard form of Indemnification Agreement.

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On February 1, 2019, the Board approved a change in the Company’s Board compensation plan for non-employee directors, pursuant to which the 2019 fee paid in respect of each such director’s service on the Board will be a cash payment of $200,000, payable in advance, subject to full clawback in connection with certain terminations of the applicable director’s service prior to December 31, 2019.

2018 Director Compensation Table

The table below summarizes the compensation paid by us to our non-employee directors for the fiscal year ended December 31, 2018.

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:

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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.

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

Equity Compensation Plan Information

The following table provides information as of December 31, 2018, regarding securities authorized for issuance under the Company’s equity compensation plans, including the MIP.

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.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth, as of April 8, 2019 , the number of shares of our equity securities beneficially owned by (i) each person known by us to be the holder of more than five percent of our voting securities, (ii) each director, (iii) each named executive officer, and (iv) all of our directors and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the SEC under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Common Stock subject to currently exercisable and convertible securities, which are exercisable or convertible within 60 days after the date of April 8, 2019 , are deemed outstanding for purposes of computing the percentage beneficially owned by the person or entity holding such securities but are not deemed outstanding for purposes of computing the percentage

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beneficially owned by any other person or entity. Unless otherwise indicated, each holder has sole voting and investment power with respect to the Common Stock owned by such holder.

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		*		%

*    Less than 1%.

(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.

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Contrarian is the investment manager for Contrarian Capital Trade Claims, L.P. (“CCTC”), Contrarian Capital Senior Secured, L.P. (“CSSM”), Contrarian Distressed Equity, L.P. (“CDE”), Contrarian Opportunity Fund L.P. (“COF”), Contrarian Centre Street Partnership, L.P. (“CCSP”), Contrarian Dome du Gouter Master Fund, LP (“CDGM”) and Contrarian Capital Fund I, L.P. (“CCI”). The managing member of Contrarian is Bauer and each of Contrarian and Bauer may be deemed to beneficially own the securities held by CCTC, CSSM, CDE, COF, CCSP, CDGM and CCI. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. The business address of CCTC, CSSM, CDE, COF, CCSP, CDGM and CCI is 411 West Putnam Ave, Ste 425, Greenwich, CT 06830.

Contrarian is the managing member of CCM Pension-A, L.L.C. (“CPENA”) and CCM Pension-B, L.L.C. (“CPENB”). The managing member of Contrarian is Bauer and each of Contrarian and Bauer may be deemed to beneficially own the securities held by CPENA and CPENB. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. The business address of CPENA and CPENB 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.

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(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.

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Director Independence

Although our Common Stock and warrants are no longer quoted on the OTCQX U.S. tier of the OTC Markets, the Board continues to comply with the independence requirements set forth in the OTCQX Rules for U.S. Companies, which require that we have at least two independent directors. Under the OTCQX Rules for U.S. Companies, an independent director is defined as any person other than an executive officer or employee of the Company or any other individual having a relationship which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities as a director. The Board has determined that each of Messrs. Albert, Bartels, Dunlevy, Hurliman, Schultz and Wells qualifies as an independent director.

Review, Approval or Ratification of Transactions with Related Persons

On August 9, 2017 the Board adopted the Related Party Transaction Policy (the “Policy”) to review and approve all Related Transactions with Related Parties, as those terms are defined in the Policy and as set forth below.

Prior to the entry of any potential Related Transaction, such transaction shall be reported to our General Counsel or, if there is no General Counsel, the Chairman of the Audit Committee, who will undertake an appropriate evaluation to determine if the

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counterparty in the transaction meets the definition of a Related Party. If that evaluation indicates that the Related Transaction would require the Audit Committee’s approval, the General Counsel or, if there is no General Counsel, the Chairman of the Audit Committee, will report the Related Transaction, together with a summary of material facts, to the Audit Committee. The Audit Committee shall review the material facts of the Related Transaction and either approve or disapprove subject to the exceptions described below. In determining whether to approve or disapprove a Related Transaction, the Audit Committee will consider whether there is a relationship that offers the potential for: (i) transactions at less than arm’s-length; (ii) favorable treatment; or (iii) the ability to influence the outcome of events differently from that which might result in the absence of that relationship.

In the event our Chief Executive Officer, Chief Financial Officer or General Counsel becomes aware of a Related Transaction that was not previously approved under the Policy, such person shall promptly notify the Chairman of the Audit Committee, and the Audit Committee or, if not practicable for us to wait for the entire Audit Committee to consider the matter, the Chairman of the Audit Committee shall consider whether the Related Transaction shall be ratified or rescinded or other action should be taken. The Chairman of the Audit Committee shall report to the Audit Committee at the next Audit Committee meeting any actions taken under the Policy.

The Audit Committee has already reviewed certain Related Transactions as described as in the Policy and determined that each of the Related Transactions described therein shall be deemed to be pre-approved or ratified, as applicable, by the Audit Committee under the terms of the Policy, unless specifically determined otherwise by the Audit Committee.

No director shall participate in any discussion or approval of a Related Transaction for which he or she is a Related Party, except that the director shall provide all material information concerning the Related Transaction to the Audit Committee.

For purposes of the Policy, a Related Party transaction is defined as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships in excess of $120,000, in which we or any of our subsidiaries is a participant, and any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director, officer or a less than ten percent beneficial owner of another entity).

For purposes of the Policy a “Related Party” is defined as any person who is or was (since the last fiscal year for which we have filed an Annual Report, even if that person does not presently serve in that role):

•	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,

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such as representation on the Board, participating in policy-making processes, material inter-company transactions, interchange of managerial personnel, or technology dependency.

Registration Rights Agreement

On the Effective Date, in accordance with the Final Plan and that certain Amended and Restated Backstop Commitment and Equity Investment Agreement, dated as of February 24, 2017, as amended and restated on May 23, 2017 (as may have been further amended from time to time, the “Amended and Restated Backstop Commitment Agreement”), the Company entered into the Registration Rights Agreement with the Registration Rights Holders (as defined in the Registration Rights Agreement), in accordance with the terms set forth in the Final Plan. The Registration Rights Agreement provides our stockholders party thereto certain registration rights.

Pursuant to the Registration Rights Agreement, the Company filed an initial shelf registration statement on Form S-1 within 90 calendar days of the Effective Date for the Registrable Securities (as defined in the Registration Rights Agreement) whose inclusion had been timely requested. Subsequent to the filing of that initial shelf registration statement, the Company filed a shelf registration statement on Form S-3 to register the unsold Registerable Securities, but due to the 2019 Chapter 11 Cases, the Company withdrew that shelf registration statement on April 9, 2019.

In addition, the Registration Rights Agreement provides the Registration Rights Holders the ability to demand registrations or underwritten shelf takedowns subject to certain requirements and exceptions, and if the Company proposes to register shares of Common Stock in certain circumstances, the Registration Rights Holders will have certain “piggyback” registration rights, subject to restrictions set forth in the Registration Rights Agreement, to include their shares of Common Stock in the registration statement.

The Registration Rights Agreement also provides that (i) for so long as the Company is subject to the requirements to publicly file information or reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, the Company will timely file all information and reports with the SEC and comply with all such requirements and (b) if the Company is not subject to the requirements of Section 13 or 15(d) of the Exchange Act, the Company will make available the information necessary to comply with Section 4(a)(7) of the Securities Act and Rule 144 and Rule 144A, if available with respect to resales of the Registrable Securities under the Securities Act, at all times, all to the extent required from time to time to enable Registration Rights Holders to sell Registrable Securities without registration under the Securities Act pursuant to the above mentioned exemptions or any other rule or regulation hereafter adopted by the SEC.

ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES

 

Our Predecessor’s audit committee engaged BDO USA, LLP (“BDO”) to serve as our independent registered public accounting firm for the fiscal years ended December 31, 2018 and December 31, 2017.

Audit Fees . Audit fees charged by BDO (“Audit Fees”) represent fees for professional services provided by our principal accountant in connection with the audit of our annual financial statements included in our annual reports for the years ended December 31, 2018 and December 31, 2017, the quarterly reviews of financial statements included in our Form 10-Q filings and other statutory or regulatory filings. For the years ended December 31, 2018 and December 31, 2017, we paid BDO Audit Fees in the amount of $560,433 and $627,000, respectively.

Audit-Related Fees . Audit-related fees charged by BDO (“Audit-Related Fees”) are fees for assurance and related services that are reasonably related to the performance by our principal accountant of the audit or review of our financial statements that are not Audit Fees. There were no Audit-Related Fees for the years ended December 31, 2018 and December 31, 2017.

Tax Fees . Tax fees charged by BDO (“Tax Fees”) include professional services performed by our principal accountant for tax compliance, tax advice and tax planning. There were no Tax Fees for the years ended December 31, 2018 or 2017.

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All Other Fees . All Other Fees includes the aggregate fees for products and services provided by our principal accountant that are not reported under “Audit Fees,” “Audit-Related Fees” or “Tax Fees.” There were no Other Fees for the years ended December 31, 2018 or December 31, 2017.

Audit Committee Pre-Approval Policies and Practices

The Audit Committee pre-approves all services provided to the Company and its subsidiaries by BDO. The Audit Committee has adopted a schedule for annual approval of the audit and related audit plan, as well as approval of other anticipated audit-related services; anticipated tax compliance, tax planning and tax advisory services; and other anticipated services. In addition, the Audit Committee (or an authorized committee member acting under delegated authority of the Audit Committee) will consider any proposed services not approved as part of this annual process. For the years ended December 31, 2018 and December 31, 2017, all audit and non-audit services were pre-approved by the Audit Committee.

  PART IV

 

ITEM 15.      EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(a)  The following documents are filed as a part of this report:

 

Financial statements

The following consolidated financial statements are included in Part II, Item 8 of this Annual Report:

	Page
Report of Independent Registered Public Accounting Firm	89
Consolidated Statements of Operations	91
Consolidated Balance Sheets	92
Consolidated Statements of Stockholders’/Members’ Equity (Deficit)	93
Consolidated Statements of Cash Flows	94
Notes to Consolidated Financial Statements	96
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	129
Supplemental Oil and Natural Gas Information	131

(b)     Exhibits

 

The following exhibits are incorporated by reference into the filing indicated or are filed herewith.

Exhibit Number		Description of Exhibit
2.1		Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 2.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
3.1		Amended and Restated Certificate of Incorporation of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.2		Amended and Restated Bylaws of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.3		Certificate of Amendment as filed with the Delaware Secretary of State (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed September 29, 2017)
4.1		Amended and Restated Indenture, dated as of August 1, 2017, among Vanguard Natural Resources, Inc., the guarantors named therein and Delaware Trust Company, as trustee and collateral trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.1		Fourth Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Vanguard Natural Gas, LLC, Citibank N.A., as Administrative Agent and the financial institutions thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)

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10.2		Amended and Restated First Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.3		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.4		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among certain subsidiaries and affiliates of Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.5		Amended and Restated Intercreditor Agreement, dated as of August 1, 2017, by and among Citibank, N.A., as priority lien agent, and Delaware Trust Company, as second lien collateral trustee, and acknowledged and agreed to by Vanguard Natural Gas, LLC, Vanguard Natural Resources, Inc. and the other grantors party thereto (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.6		Amended and Restated Collateral Trust Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., the grantors and guarantors named therein and Delaware Trust Company as trustee and as collateral trustee (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.7		Registration Rights Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc. and certain parties thereto (incorporated by reference to Exhibit 10.7 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.8		Warrant Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc., as Issuer, and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.9*		Second Amended and Restated Employment Agreement of Scott W. Smith, dated August 1, 2017 (incorporated by reference to Exhibit 10.9 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.10*		Second Amended and Restated Employment Agreement of Britt Pence, dated August 1, 2017 (incorporated by reference to Exhibit 10.11 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.11*		Employment Agreement of Jonathan C. Curth, dated January 22, 2019 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed January 28, 2019)
10.12*		Employment Agreement with Richard Scott Sloan, dated January 22, 2019 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 28, 2019)
10.13*		Employment Agreement with Ryan Midgett, dated January 22, 2019 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed January 28, 2019)
10.14*		Vanguard Natural Resources, Inc. Management Incentive Plan (incorporated by reference to Exhibit 10.13 to our Quarterly Report on Form 10-Q filed November 9, 2017)
10.15**		Form of Director Deferred Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the year ended December 31, 2017 filed on March 21, 2018)
10.16*		Form of Restricted Stock Unit Award Agreement (Performance Based) (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed January 18, 2018)
10.17*		Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed January 18, 2018)
10.18		Limited Waiver and First Amendment, dated January 9, 2018, to the Fourth Amended and Restated Credit Agreement, among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC, Vanguard Operating, LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed July 9, 2018)
10.19		Second Amendment to Credit Agreement, dated July 5, 2018, to the Fourth Amended and Restated Credit Agreement, among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC, Citibank N.A., as Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed July 9, 2018)
10.20		Third Amendment to Fourth Amended and Restated Credit Agreement, dated December 6, 2018, to the Fourth Amended and Restated Credit Agreement, among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC, Citibank N.A., as Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 10, 2018)
10.21*		Vanguard Natural Resources, Inc. 2019 Short Term Incentive Plan
10.22*		Vanguard Natural Resources, Inc. 2019 Incentive Plan

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10.23		Ratification and Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated March 31, 2019, among Vanguard Natural Gas, LLC, Vanguard Natural Resources, Inc., Citibank N.A., as Administrative Agent and lenders party thereto
21.1**		Subsidiaries of Vanguard Natural Resources, Inc.
24.1		Power of Attorney (included on signature page hereto)
31.1**		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2**		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1**		Section 906 of the Sarbanes Oxley Act Certification of Chief Executive Officer
32.2**		Section 906 of the Sarbanes Oxley Act Certification of Chief Financial Officer
99.1**		Report of Miller and Lents, Ltd., Independent Petroleum Engineers and Geologists
99.2		Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 99.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
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

_______________

*    Management Contract or Compensatory Plan or Arrangement required to be filed as an Exhibit hereto pursuant to Item 601 of Regulation S-K

**	Filed herewith.

***	Furnised herewith.

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ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 15th day of April, 2019.

 

VANGUARD NATURAL RESOURCES, INC.
		/s/ R. Scott Sloan
		R. Scott Sloan
		President and Chief Executive Officer

 

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints R. Scott Sloan, Ryan Midgett and Jonathan Curth, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this Annual Report, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

158

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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

159