UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to

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)

(832) 327-2255

(Registrant’s Telephone Number, Including Area Code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☑  Yes o No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    ☑  Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13 (a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☑  Yes ☐ No

Securities registered pursuant to Section 12(b) of the Act: None

As of May 10, 2019, the registrant had 20,124,080 outstanding shares of common stock, $0.001 par value.

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Unaudited Condensed Consolidated Financial Statements
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Equity	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	43

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

When we refer to oil, natural gas and natural gas liquids (“NGLs”) in “equivalents,” we are doing so to compare quantities of natural gas with quantities of NGLs and oil or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil or one Bbl of NGLs and one Bbl of oil or one Bbl of NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

References in this report 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 the 2017 Chapter 11 bankruptcy cases on August 1, 2017 (the “Effective Date”) and to Vanguard Natural Resources, Inc. for the period as of and following the Effective Date.

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q (the “Quarterly Report”) may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Statements included in this Quarterly Report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements.  These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Forward-looking statements include, but are not limited to, statements we make concerning future actions, conditions or events, future operating results, income or cash flow.

These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in the Risk Factors section of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “2018 Annual Report”), and this Quarterly Report, and those set forth from time to time in our filings with the Securities and Exchange Commission (the “SEC”), which are available on our website at www.vnrenergy.com and through the SEC’s Electronic Data Gathering and Retrieval System at www.sec.gov. These factors and risks include, but are not limited to:

• 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) described below, including our inability to confirm and consummate the 2019 Plan (as defined herein);

• 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;

• 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.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

PART I – FINANCIAL INFORMATION

Item 1. Unaudited Condensed Consolidated Financial Statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(Debtor-in-Possession)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended
	March 31,
	2019			2018
Revenues:
Oil sales	$	32,748		$	46,111
Natural gas sales	62,314			55,267
NGLs sales	14,048			21,897
Oil, natural gas and NGLs sales	109,110			123,275
Net losses on commodity derivative contracts	(61,139		)	(18,585		)
Total revenues and losses on commodity derivative contracts	47,971			104,690
Costs and expenses:
Production:
Lease operating expenses	26,247			30,995
Transportation, gathering, processing and compression	9,522			11,502
Production and other taxes	9,823			9,781
Depreciation, depletion, amortization, and accretion	35,714			40,039
Impairment of oil and natural gas properties	438			14,601
Exploration expense	201			1,316
Selling, general and administrative expenses	12,557			12,736
Total costs and expenses	94,502			120,970
Loss from operations	(46,531		)	(16,280		)
Other income (expense):
Interest expense	(16,975		)	(14,753		)
Net loss on divestiture of oil and natural gas properties	(458		)	—
Other	87			149
Total other expense, net	(17,346		)	(14,604		)
Loss before reorganization items	(63,877		)	(30,884		)
Reorganization items (Note 3)	(18,388		)	(1,707		)
Net loss	(82,265		)	(32,591		)
Less: Net income attributable to non-controlling interests	—			(93		)
Net loss attributable to Common stockholders	$	(82,265	)	$	(32,684	)
Net loss per share – basic and diluted	$	(4.09	)	$	(1.63	)
Weighted average Common shares outstanding
Common shares – basic and diluted	20,124			20,100

See accompanying notes to condensed consolidated financial statements

3

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(Debtor-in-Possession)

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

(Unaudited)

	March 31, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	5,512		$	33,538
Trade accounts receivable, net	55,119			62,073
Derivative assets	1,948			6,287
Restricted cash	3,750			4,450
Prepaid drilling costs	12,519			12,476
Other current assets	11,936			5,663
Total current assets	90,784			124,487
Oil and natural gas properties
Proved properties	1,563,760			1,567,903
Unproved properties	81,597			81,597
	1,645,357			1,649,500
Accumulated depletion, amortization and impairment	(302,521		)	(269,972		)
Oil and natural gas properties, net – successful efforts	1,342,836			1,379,528
Other assets
Lease assets	15,503			—
Derivative assets	—			6,766
Other assets	17,043			9,321
Total assets	$	1,466,166		$	1,520,102
Liabilities and equity
Current liabilities
Accounts payable:
Trade	$	—		$	29,709
Accrued liabilities:
Lease operating	—			13,140
Developmental capital	—			6,937
Interest	—			4,999
Production and other taxes	—			23,658
Other	4,426			12,175
Derivative liabilities	—			6,483
Oil and natural gas revenue payable	—			35,802
Long-term debt classified as current	—			879,181
Other current liabilities	—			9,091
Total current liabilities	4,426			1,021,175
Long-term debt, net of current portion (Note 6)	—			5,446
Asset retirement obligations	140,615			139,433
Other long-term liabilities	—			523
Total liabilities not subject to compromise	145,041			1,166,577
Liabilities subject to compromise (Note 3)	1,049,274			—
Total liabilities	1,194,315			1,166,577
Commitments and contingencies (Note 11)
Stockholders’ equity (Note 12)
Common stock ($0.001 par value, 50,000,000 shares authorized; 20,124,080 shares issued and outstanding at March 31, 2019 and December 31, 2018)	20			20
Additional paid-in capital	509,477			508,886
Accumulated deficit	(237,646		)	(155,381		)
Total stockholders' equity	271,851			353,525
Total liabilities and equity	$	1,466,166		$	1,520,102

See accompanying notes to condensed consolidated financial statements

4

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(Debtor-in-Possession)

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)

(Unaudited)

	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders' Equity
	Shares	Amount
Balance at December 31, 2018	20,124	$	20	$	508,886	$	(155,381	)	$	353,525
Net loss	—	—		—		(82,265		)	(82,265		)
Share-based compensation	—	—		591		—			591
Balance at March 31, 2019	20,124	$	20	$	509,477	$	(237,646	)	$	271,851

	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders' Equity
	Shares	Amount
Balance at December 31, 2017	20,100	$	20	$	506,640	$	(111,410	)	$	2,278		$	397,528
Net income (loss)	—	—		—		(32,684		)	93			(32,591		)
Share-based compensation	—	—		496		—			—			496
Potato Hills cash distribution to non-controlling interest	—	—		—		—			(177		)	(177		)
Balance at March 31, 2018	20,100	$	20	$	507,136	$	(144,094	)	$	2,194		$	365,256

See accompanying notes to condensed consolidated financial statements

5

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(Debtor-in-Possession)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Operating activities
Net loss	$	(82,265	)	$	(32,591	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization, and accretion	35,714			40,039
Impairment of oil and natural gas properties	438			14,601
Amortization of deferred financing costs	830			677
Compensation related items	591			496
Net losses on commodity derivative contracts	61,139			18,585
Cash settlements paid on matured commodity derivative contracts	(16,089		)	(9,292		)
Net loss on divestiture of oil and natural gas properties	458			—
Non-cash reorganization items (Note 3)	6,311			—
Changes in operating assets and liabilities:
Trade accounts receivable	6,496			13,905
Other current assets	(6,359		)	(692		)
Accounts payable and oil and natural gas revenue payable	(15,058		)	(3,191		)
Accrued expenses and other current liabilities	(729		)	(6,292		)
Other assets	(7,807		)	4
Net cash provided by (used in) operating activities	(16,330		)	36,249
Investing activities
Additions to property and equipment	(31		)	(68		)
Additions to oil and natural gas properties	(4,012		)	(23,270		)
Deposits and prepayments of oil and natural gas properties	(7,033		)	(20,777		)
Proceeds from the sale of oil and natural gas properties	4,461			—
Net cash used in investing activities	(6,615		)	(44,115		)
Financing activities
Proceeds from long-term debt	—			48,000
Repayment of long-term debt	(5,775		)	(34,554		)
Potato Hills distribution to non-controlling interest	—			(177		)
Financing fees	(6		)	(33		)
Net cash provided by (used in) financing activities	(5,781		)	13,236
Net increase (decrease) in cash, cash equivalents and restricted cash	(28,726		)	5,370
Cash, cash equivalents and restricted cash, beginning of period	37,988			10,017
Cash, cash equivalents and restricted cash, end of period	$	9,262		$	15,387
Supplemental cash flow information:
Cash paid for interest	$	8,616		$	16,155
Non-cash financing and investing activities:
Lease assets obtained in exchange for lease liabilities	$	110		$	—
Asset retirement obligations, net	$	229		$	136
Reconciliation of Cash and Cash Equivalents and Restricted Cash
Cash and cash equivalents at beginning of period	$	33,538		$	2,762
Restricted cash at beginning of period	4,450			7,255
Cash and cash equivalents and restricted cash at beginning of period	$	37,988		$	10,017
Cash and cash equivalents at end of period	$	5,512		$	9,144
Restricted cash at end of period	3,750			6,243
Cash and cash equivalents and restricted cash at end of period	$	9,262		$	15,387

See accompanying notes to condensed consolidated financial statements

6

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(Debtor-in-Possession)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

(Unaudited)

Description of the Business

We are an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. We are currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of March 31, 2019, we own properties and oil and natural gas reserves primarily located in nine operating areas:

• the Green River Basin in Wyoming;

• the Piceance Basin in Colorado;

• the Permian Basin in West Texas and New Mexico;

• the Arkoma Basin in Oklahoma;

• the Gulf Coast Basin in Texas, Louisiana and Alabama;

• the Big Horn Basin in Wyoming and Montana;

• the Anadarko Basin in Oklahoma and North Texas;

• the Wind River Basin in Wyoming; and

• the Powder River Basin in Wyoming.

On March 31, 2019 (the “2019 Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “2019 Debtors”) filed voluntary petitions for relief (collectively, the “2019 Bankruptcy Petitions” and, the cases commenced thereby, the “2019 Chapter 11 Cases”) under Chapter 11 of title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The 2019 Chapter 11 Cases are being jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.” See Note 3 for a discussion of the Chapter 11 proceedings.

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

The Company’s shares of common stock and warrants are traded and quoted on the OTC Pink marketplace (the “OTC Pink”) under the symbols VNRRQ, VNRVQ and VNRWQ, respectively.

7

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 2019 Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. Please see Note 3, “2019 Chapter 11 Proceedings,” for further discussion.

2.  Summary of Significant Accounting Policies

The accompanying condensed consolidated financial statements are unaudited and were prepared from our records. We derived the condensed consolidated balance sheet as of December 31, 2018 from the audited financial statements contained in our 2018 Annual Report.  Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report along with our 2018 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year.

As of March 31, 2019, our significant accounting policies are consistent with those discussed in Note 1 of the Notes to the Consolidated Financial Statements contained in our 2018 Annual Report.

(a) Basis of Presentation and Principles of Consolidation

The condensed consolidated financial statements as of March 31, 2019 and December 31, 2018, and for the three months ended March 31, 2019 and 2018, respectively, include our accounts and those of our subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation.

Prior to August 2018, we consolidated the Potato Hills Gas Gathering System as we had the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our condensed consolidated financial statements. On August 1, 2018, we completed the sale of our 51% joint venture interest in Potato Hills Gas Gathering System, including the compression assets relating to the gathering system and our working interest in related oil and natural gas producing properties.

For periods subsequent to filing the 2019 Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

(b) Oil and Natural Gas Properties

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

Depreciation, depletion and amortization

8

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

Impairment of Oil and Natural Gas Properties

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

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

(c) Income Taxes

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2019, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

(d) New Pronouncements Recently Adopted

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

We adopted ASU No. 2016-02 as of January 1, 2019, using the targeted improvement transition option included in ASU No. 2018-11 - Leases (Topic 842). The targeted improvement approach allows us to apply the standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, we elected the package of practical expedients permitted under the transition guidance within the new standard, which allowed us to carry forward the historical lease classification and not capitalize leases with terms of 12 months or less without a purchase option. In addition, it allowed us not to separate lease and non-lease components. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements.

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The adoption of ASU 2016-02 resulted in the recording of additional net lease assets and lease liabilities of approximately $17.5 million and $18.0 million, respectively, as of January 1, 2019, with the difference largely due to prepaid and deferred rent that were reclassified to the right-of-use (“ROU”) asset value. The standard did not require any adjustment to the opening balance of retained earnings and had no impact on cash flows. Please see Note 10, “Leases,” for further details.

In February 2018, the FASB issued ASU No. 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. U.S. GAAP requires deferred tax liabilities and assets to be adjusted for the effect of a change in tax laws or rates, with the effect included in income from continuing operations in the reporting period that includes the enactment date, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income (referred to as “stranded tax effects”). The amendments in this ASU allow a specific exception for reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. In addition, the amendments in this update also require certain disclosures about stranded tax effects. We applied the update beginning January 1, 2019. The adoption of this new guidance had no material impact on our consolidated financial statements.

(e) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related future cash flows, the fair value of derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to DD&A and accretion expense, income taxes, and non-cash compensation. Actual results could differ from those estimates.

(f) Prior Year Financial Statement Presentation

Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report.

3.     2019 Chapter 11 Proceedings

Commencement of Bankruptcy Cases

On March 31, 2019, the 2019 Debtors filed the 2019 Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court. The 2019 Debtors are being jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

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

Reorganization Process

We are currently operating our business as a debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We expect to generally continue our operations without interruption during the pendency of the 2019 Chapter 11 Cases. To continue ordinary course operations, we secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees.

Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the Petition Date were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our prepetition liabilities and obligations should (subject to certain exceptions) be settled or compromised under the Bankruptcy Code through the 2019 Chapter 11 Cases.

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Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2018 Annual Report on Form 10-K and Part II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q. These include risks and uncertainties arising as a result of the 2019 Chapter 11 Cases, and the number and nature of our outstanding shares and shareholders, assets, liabilities, officers and directors could change materially because of the 2019 Chapter 11 Cases.

Creditors’ Committees - Appointment & Formation

Official Unsecured Creditors Committee

On April 11, 2019, the Office of the United States Trustee appointed the Official Committee of Unsecured Creditors (the “Unsecured Creditors Committee”) pursuant to section 1102 of the Bankruptcy Code. The Unsecured Creditors Committee consists of the following three members: (i) Enterprise Jonah Gas Gathering LLC; (ii) Viva Energy Services LLC; and (iii) Trinity Environmental SWD I, LLC.

Exclusivity; Plan of Reorganization

Under the Bankruptcy Code, we have the exclusive right to file a plan of reorganization under Chapter 11 through and including July 29, 2019, and to solicit acceptances of such plan through September 27, 2019. We filed a Chapter 11 plan of reorganization, together with an accompanying disclosure statement on April 30, 2019 (as may be amended, modified, or supplemented from time to time, the “2019 Plan”). We plan to emerge from our Chapter 11 cases after we obtain approval from the Bankruptcy Court confirming the 2019 Plan. Among other things, the Plan determines the rights and satisfy the claims of our creditors and security holders. The 2019 Plan is subject to further negotiations with stakeholders and, possibly, decisions by the Bankruptcy Court.

Under the absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common stock can receive any distribution or retain any property under a plan of reorganization. The 2019 Plan currently does not contemplate providing any economic recovery to holders of our existing common stock. The ultimate recovery to creditors, if any, will not be determined until confirmation and implementation of the 2019 Plan. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors. Our Plan could result in any of the holders of our liabilities receiving no distribution on account of their interests and cancellation of their holdings. Moreover, the 2019 Plan can be confirmed, under the Bankruptcy Code even though the 2019 Plan provides that the holders of our common stock receive no distribution on account of their equity interests.

Schedules and Statements - Claims & Claims Resolution Process

To the best of our knowledge, after making reasonable efforts, we have notified all of our known current or potential creditors that the 2019 Debtors have filed Chapter 11 cases. On May 6, 2019 each of the 2019 Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the 2019 Debtors, including executory contracts to which each of the 2019 Debtors is a party, are subject to the qualifications and assumptions included therein, and are subject to amendment or modification as our Chapter 11 cases proceed. The Schedules and Statements may be subject to further amendment or modification after filing. Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wish to assert prepetition claims against us and whose claim (i) is not listed in the Schedules and Statements or (ii) is listed in the Schedules and Statements as disputed, contingent, or unliquidated, must file a proof of claim with the Bankruptcy Court prior to the bar date set by the court. The bar dates are June 14, 2019, for non-governmental creditors, and September 27, 2019, for governmental creditors.

As of May 10, 2019, approximately 83 claims totaling $2.3 million have been filed with the Bankruptcy Court against the 2019 Debtors by approximately 73 claimants. We expect additional claims to be filed prior to the bar dates. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We anticipate the claims filed against the 2019 Debtors in the 2019 Chapter 11 Cases will be numerous. We expect the process of resolving claims filed against the 2019 Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with the 2019 Plan. As part of the process, we will work to resolve differences in amounts scheduled by the 2019 Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where

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necessary. Accordingly, the ultimate number and amount of claims that will be allowed against the 2019 Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Plan Support Agreement

On May 8, 2019, the 2019 Debtors entered into a Plan Support Agreement (the “Plan Support Agreement”) with (a) certain holders (the “RBL Lenders”) constituting over 66 2/3% in amount and over 50.1% in number of the revolving credit facility claims and over 66 2/3% in amount and over 50.1% in number of those certain secured swap claims, in each case under that certain Fourth Amendment and Restated Credit Agreement, dated as of August 1, 2017, by and among Vanguard Natural Gas, LLC, as borrower, the guarantors party thereto, Citibank N.A., as Administrative Agent, and the other lenders party thereto from time to time (as amended, the “Successor Credit Facility” and the claims thereunder, the “RBL Claims” and “Secured Swap Claims,” as applicable); and (b) certain holders (the “Term Loan Lenders” and, collectively with the RBL Lenders, the “Plan Support Parties”), constituting over 66 2/3% in amount and over 50.1% in number of the term loan claims under the Successor Credit Facility (the “Term Loan Claims”).

The Plan Support Agreement sets forth, subject to certain conditions, the commitment of the 2019 Debtors and the Plan Support Parties to support a comprehensive restructuring of the 2019 Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through the 2019 Plan.

The Restructuring Transactions will be financed by (i) the issuance of new common stock in the reorganized Company (the “New Common Stock”); (ii) the issuance of a new series of class A preferred stock in the reorganized Company (the “New Preferred Equity Class A Stock”); (iii) potentially the issuance of a new series of class B preferred stock in the reorganized Company (the “New Preferred Equity Class B Stock”); (iv) a new first lien reserve-based revolving credit facility with an initial borrowing base of $65.0 million and a term loan lending facility in the aggregate amount of $65.0 million (the “Exit RBL/Term Loan A Facility”); and (v) a new term loan lending facility in the aggregate amount of $285.0 million (the “Exit Term Loan B Facility,” and together with the Exit RBL/Term Loan A Facility, the “Exit Facilities”). The material terms of the Exit Facilities will be filed in advance of the hearing to consider confirmation of the 2019 Plan.

Pursuant to the Plan Support Agreement, the Company intends to commence the solicitation of votes on the 2019 Plan on May 28, 2019, by causing the 2019 Plan and related disclosure statement to be distributed consistent with section 1126(b) of the Bankruptcy Code. Certain principal terms of the 2019 Plan are outlined below:

• holders of Allowed DIP Facility Claims (as defined in the 2019 Plan) will receive their pro rata share of participation in the Exit RBL/Term Loan A Facility;

• holders of Allowed Revolving Credit Facility Claims and Allowed Secured Swap Claims (each as defined in the 2019 Plan) will receive their pro rata share of and interest in: (i) the Exit Term Loan B Facility; (ii) at least 86.1% of the New Preferred Equity Class A Stock; and (iii) 75% or 89% of the New Common Stock, depending on whether the class of holders of Allowed Senior Note Claims (as defined in the 2019 Plan) votes to accept or reject the 2019 Plan, and subject to dilution on account of the Management Incentive Plan (as defined below) (if any);

• holders of Allowed Term Loan Claims will receive a pro rata share and interest in 10% of the New Common Stock, subject to dilution on account of the Management Incentive Plan (if any), as well as at the option of each holder of an Allowed Term Loan Claim, either: (i) such holder’s pro rata share of the New Preferred Equity Class A Stock available to such holders in accordance with the Preferred Equity Documents (as defined in the Plan Support Agreement) (albeit the maximum amount of New Preferred Equity Class A Stock available to all holders of Allowed Term Loan Claims who elect such option shall not exceed 13.9% percent of the New Preferred Equity Class A Stock to be distributed in the aggregate); or (ii) such holder’s pro rata share of the New Preferred Equity Class B Stock;

• holders of Allowed Senior Note Claims will receive a pro rata share and interest in: (i) 15% of the New Common Stock, if the class of Allowed Senior Note Claims votes to accept the 2019 Plan, subject to dilution on account of the Management Incentive Plan (if any); or (ii) 1% of the New Common Stock, if the class of Allowed Senior Note Claims votes to reject the 2019 Plan, subject to dilution on account of the Management Incentive Plan (if any);

• holders of Allowed General Unsecured Claims (as defined in the Plan Support Agreement) shall receive (to the extent such General Unsecured Claims have not already been paid in full during the 2019 Chapter 11 Cases), in full and final satisfaction, settlement, release, and discharge of, and in exchange for each Allowed General Unsecured Claim, on the Effective Date such treatment as is acceptable to the 2019 Debtors, the Required Consenting Revolver Lenders (as defined in the 2019 Plan), and the DIP Agent (as defined in the 2019 Plan) and in accordance with the Bankruptcy Code, to be

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determined prior to the hearing to consider approval of the Disclosure Statement; and

• the 2019 Plan may provide for the establishment of a customary management incentive plan at the Company to the officers and other key employees of the respective reorganized entities (the “Management Incentive Plan”). The 2019 Plan will provide for releases of specified claims held by the 2019 Debtors, the Plan Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions.

The Plan Support Agreement obligates the 2019 Debtors and the Plan Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Plan Support Parties, vote their claims in favor of the 2019 Plan. We believe the Plan Support Agreement will contribute to reducing the duration of the 2019 Chapter 11 Cases. The Plan Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation and consummation of the 2019 Plan, among other requirements, and in the event of certain breaches by the parties under the Plan Support Agreement. Except as otherwise agreed by the 2019 Debtors and the Plan Support Parties, the Plan Support Agreement contemplates the effective date of the Plan will be no later than 120 days after the filing of the 2019 Bankruptcy Petitions, and the Plan Support Agreement will be subject to termination if the effective date of the 2019 Plan has not occurred within that time. There can be no assurances that the Restructuring Transactions will be consummated. See Part II, Item 1A, “Risk Factors” “If the Plan Support Agreement is terminated, our ability to confirm and consummate a Chapter 11 plan of reorganization could be materially and adversely affected.”

Debtor-in-Possession Financing

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

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

• a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under the Successor Credit Facility (as defined in Note 6) (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);

• proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;

• the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (c) the occurrence of an event of default (subject to any cure periods), and (d) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases.

• interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%, or the adjusted base rate plus 4.50% per annum;

• in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the New Money Facility, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;

• the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of

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

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

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

The relief requested in the DIP Motion was approved by the Bankruptcy Court on April 30, 2019.

Acceleration of Debt Obligations

As of December 31, 2018, the Company was not in compliance with certain covenants under the Successor Credit Facility (as defined in Note 6). Accordingly, all amounts due under the Successor Credit Facility and New Notes (as defined in Note 6) (collectively, the “Debt Instruments”) are classified as current in the accompanying consolidated balance sheets as of that date. The commencement of the 2019 Chapter 11 Cases is an event of default that accelerated the 2019 Debtors’ obligations under these Debt Instruments as described in further detail below. In addition, as of March 31, 2019, amounts outstanding under the Debt Instruments are included in liabilities subject to compromise in the condensed consolidated balance sheets. Further, in accordance with accounting guidance in ASC 852, we will not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases.

• $677.7 million in unpaid principal with respect to the Revolving Loan (defined in Note 6), $123.4 million in unpaid principal with respect to the Term Loan (defined in Note 6), and approximately $11.6 million of interest, fees, and other expenses arising under or in connection with the Successor Credit Facility.

• $80.7 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the New Notes issued pursuant to the Amended and Restated Indenture.

Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code.

Liabilities Subject to Compromise

Liabilities subject to compromise represent estimates of known or potential prepetition claims expected to be resolved in connection with the 2019 Chapter 11 Cases. Additional amounts may be included in liabilities subject to compromise in future periods if we elect to reject executory contracts and unexpired leases as part of our 2019 Chapter 11 Cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Quarterly Report on Form 10-Q and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the Chapter 11 process, and we will make adjustments in future periods as necessary and appropriate. Such adjustments may be material.

Under the Bankruptcy Code, we may assume, assign or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. If we reject a contract or lease, such rejection generally (1) is treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieves the 2019 Debtors of performing their future obligations under such contract or lease and (3) entitles the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. If we assume an executory contract or unexpired lease, we are generally required to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty.

The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of March 31, 2019:

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	March 31, 2019
	(in thousands)
Accounts payable	$	17,000
Accrued liabilities	42,507
Undistributed oil and gas revenues	33,453
Derivative liabilities	40,428
Other liabilities	5,425
Debt and accrued interest	894,407
Lease liabilities	16,054
Liabilities subject to compromise	$	1,049,274

Reorganization Items

We use this category to reflect, where applicable, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. The following table summarizes the components included in reorganization items on our consolidated statements of operations for three months ended March 31, 2019:

	Three Months Ended March 31, 2019
	(in thousands)
Professional and legal fees (1)	$	12,077
Deferred financing costs and debt discount (2)	6,311
Total Reorganization items	$	18,388

(1) All professional and legal fees were incurred and paid as of March 31, 2019.

(2) Includes a non-cash charge to write off of the unamortized debt issuance costs and debt discounts of $6.3 million related to the Revolving Loan, Term Loan and New Notes as these debt instruments are expected to be impacted by the bankruptcy reorganization process.

4.  Revenues

Revenue from Contracts with Customers

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

Natural gas and NGLs Sales

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

In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price

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from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as Transportation, gathering, processing and compression expense in our condensed consolidated statements of operations.

Oil sales

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

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

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

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. For the three months ended March 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

5.  Divestitures

During March 2019, the Company completed the sale of certain oil and natural gas properties in the Jonah Field in the Green River Basin. Cash proceeds received from the sale were approximately $4.4 million, subject to customary post-closing adjustments, net of costs to sell of $0.2 million. The net cash proceeds from this divestment were used to pay down outstanding debt under the Successor Credit Facility (defined in Note 6, “Debt”).

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6. Debt

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

Description	Interest Rate	Maturity Date	March 31, 2019			December 31, 2018
Revolving Loan	Variable (1)	February 1, 2021	$	677,718		$	682,145
Term Loan	Variable (2)	May 1, 2021	123,438			123,438
New Notes	9.0%	February 15, 2024	80,722			80,722
Lease Financing Obligations	4.16%	August 10, 2020 (3)	—			10,454
Unamortized deferred financing costs			—			(7,124		)
Total debt			$	881,878		$	889,635
Less:
Liabilities subject to compromise (Note 3)			(881,878		)	—
Long-term debt classified as current (4)			—			(879,181		)
Current portion of Lease Financing Obligation (3)			—			(5,008		)
Total long-term debt			$	—		$	5,446

(1) Variable interest rate of 6.53% and 6.27% at March 31, 2019 and December 31, 2018, respectively.

(2) Variable interest rate of 10.28% and 9.96% at March 31, 2019 and December 31, 2018, respectively.

(3) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Assets” line item in the Balance Sheet. See Note 10, “Leases,” for a detailed discussion of our leases.

(4) Under ASC Topic 470, “Debt,”, as a result of our debt covenant violations, we classified our debt under our Revolving Loan, Term Loan and New Notes, as current at December 31, 2018.

Acceleration of Debt Obligations

As of December 31, 2018, the Company was not in compliance with certain covenants under the Successor Credit Facility (defined herein). Accordingly, all amounts due under the Debt Instruments are classified as current in the accompanying consolidated balance sheets as of that date. The commencement of the 2019 Chapter 11 Cases is an event of default that accelerated the 2019 Debtors’ obligations under these Debt Instruments. As of March 31, 2019, amounts outstanding under the Debt instruments are included in liabilities subject to compromise in the condensed consolidated balance sheets. Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code. Further, in accordance with accounting guidance in ASC 852, we will not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases.

Successor Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “Successor Credit Facility”), the lenders party thereto agreed to provide VNG with an $850.0 million senior secured reserve-based revolving credit facility (the “Revolving Loan”). The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). As of March 31, 2019, the Successor Credit Facility had a borrowing base of $677.9 million.

As discussed in Note 5, “Divestitures,” the net cash proceeds received from the sale of properties of $4.4 million were used to pay down debt. At March 31, 2019, there were $677.7 million of outstanding borrowings under the Successor Credit Facility.

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

The maturity date of the Successor Credit Facility is February 1, 2021 with respect to the Revolving Loans and May 1, 2021 with respect to the Term Loan. Until the maturity date for the Term Loan, the Term Loan shall bear an interest rate equal to (i) the alternative base rate plus an applicable margin of 6.50% for an Alternate Base Rate loan or (ii) adjusted 30-day LIBOR plus an applicable margin of 7.50% for a Eurodollar loan. Until the maturity date for the Revolving Loans, the

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Revolving Loans shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 1.75% to 2.75%, based on the borrowing base utilization percentage under the Successor Credit Facility or (ii) adjusted 30-day LIBOR plus an applicable margin of 2.75% to 3.75%, based on the borrowing base utilization percentage under the Successor Credit Facility.

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

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

VNG is required to repay the Term Loans on the last day of each March, June, September and December (commencing with the first full fiscal quarter ended after August 1, 2017), in each case, in an amount equal to 0.25% of the original principal amount of such Term Loans and, on the Maturity Date, the remainder of the principal amount of the Term Loans outstanding on such date, together in each case with accrued and unpaid interest on the principal amount to be paid but excluding the date of such payment. The table below shows the amounts of required payments under the Term Loan for each year as of March 31, 2019 (in thousands):

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

As discussed above, all amounts due under our Successor Credit Facility are included in liabilities subject to compromise as of March 31, 2019 in the accompanying condensed consolidated balance sheets.

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

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

The Successor Credit Facility contains certain customary representations and warranties and certain customary affirmative and negative covenants. In addition, the Successor Credit Facility also contains certain financial covenants, as amended under the Second Amendment, including the maintenance of:

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

Period	Ratio
March 31, 2019	5.75:1.0
June 30, 2019	5.25:1.0
September 30, 2019	5.00:1.0
December 31, 2019 and March 31, 2020	4.75:1.0
June 30, 2020	4.50:1.0
September 30, 2020	4.25:1.0
December 31, 2020 and thereafter	4.00:1.0

; and

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(ii) a ratio, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending December 31, 2017, of current assets to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than 1.00 to 1.00.

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

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

New Notes

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes”) to certain eligible holders of the Predecessor’s second lien notes (the “Existing Notes”) in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders.

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

The New Notes are governed by an Amended and Restated Indenture, dated as of August 1, 2017 (as amended, the “Amended and Restated Indenture”), by and among the Company, certain subsidiary guarantors of the Company (the “Guarantors”) and Delaware Trust Company, as Trustee (in such capacity, the “Trustee”) and as Collateral Trustee (in such capacity, the “Collateral Trustee”), which contains customary affirmative and negative covenants.

The Amended and Restated Indenture also contains customary events of default, including (i) default for thirty (30) days in the payment when due of interest on the Senior Notes due 2024; (ii) default in payment when due of principal of or premium, if any, on the Senior Notes due 2024 at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency with respect to the Company or any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that taken together would constitute a significant subsidiary.

Interest is payable on the Senior Notes due 2024 on February 15 and August 15 of each year, which began on February 15, 2018. The Senior Notes due 2024 will mature on February 15, 2024.

At any time prior to February 15, 2020, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Senior Notes due 2024 issued under the Amended and Restated Indenture, with an amount of cash not greater than the net cash proceeds of certain equity offerings, at a redemption price equal to 109% of the principal amount of the Senior Notes due 2024, together with accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% of the aggregate principal amount of the Senior Notes due 2024 originally issued under the Amended and Restated Indenture remain outstanding after such redemption, and (ii) the redemption occurs within one hundred eighty (180) days of the equity offering.

On or after February 15, 2020, the Senior Notes due 2024 will be redeemable, in whole or in part, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

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

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In addition, at any time prior to February 15, 2020, the Company may on any one or more occasions redeem all or a part of the Senior Notes due 2024 at a redemption price equal to 100% of the principal amount thereof, plus the Applicable Premium (as defined in the Amended and Restated Indenture) as of, and accrued and unpaid interest, if any, to the date of redemption.

7. Price Risk Management Activities

We have entered into derivative contracts primarily with counterparties that are also lenders under our Successor Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. Our derivative contracts with these counterparties are governed by master agreements, which generally specify that a default under any of our debt agreements as well as any bankruptcy filing is an event of default which may result in early termination of such derivative contracts. As a result of our defaults under our debt agreements and our 2019 Bankruptcy Petitions, we were in default under our derivative contracts. In addition, our derivative contract counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the 2019 Debtors as a result of such terminations, in accordance with the terms of the agreements governing such derivative contracts. In April 2019, our derivative contract counterparties unilaterally terminated all derivative contracts to which we were a party and the net settlement owed to counterparties amounted to $53.9 million.

While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in over hedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points.

The following tables summarize oil, natural gas, and NGLs commodity derivative contracts in place at March 31, 2019:

Fixed-Price Swaps (NYMEX)

	Gas			Oil			NGLs
Contract Period	MMBtu	WeightedAverage Fixed Price		Bbls	Weighted Average WTI Price		Gallons	Weighted Average Fixed Price
April 1, 2019 - December 31, 2019	36,429,000	$	2.75	1,393,300	$	48.49	14,666,518	$	0.91
January 1, 2020 - December 31, 2020	47,227,500	$	2.75	1,393,800	$	49.53	—	$	—

Basis Swaps

	Gas
Contract Period	MMBtu	Weighted Avg. Basis Differential ($/MMBtu)			Pricing Index
April 1, 2019 - December 31, 2019	11,000,000	$	(0.57	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
April 1, 2019 - December 31, 2019	4,125,000	$	(0.25	)	Enable East Gas and NYMEX Henry Hub Basis Differential

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	Oil
Contract Period	Bbls	WeightedAvg. Basis Differential ($/Bbl)			Pricing Index
April 1, 2019 - December 31, 2019	343,750	$	(5.78	)	WTI Midland and WTI Cushing Basis Differential
January 1, 2020 - December 31, 2020	366,000	$	(0.10	)	WTI Midland and WTI Cushing Basis Differential
April 1, 2019 - December 31, 2019	137,500	$	(20.40	)	WTI and WCS Basis Differential

Collars

	Gas					Oil
Contract Period	MMBtu	Floor Price ($/MMBtu)		Ceiling Price ($/MMBtu)		Bbls	Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
April 1, 2019 - December 31, 2019	4,125,000	$	2.60	$	3.00	424,370	$	43.78	$	54.03
January 1, 2020 - December 31, 2020	5,490,000	$	2.60	$	3.00	659,340	$	44.17	$	55.00
January 1, 2021 - December 31, 2021	1,825,000	$	2.60	$	3.07	294,536	$	55.25	$	63.76

Balance Sheet Presentation

Our commodity derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the condensed consolidated balance sheets as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed consolidated balance sheets for the periods indicated (in thousands):

	March 31, 2019
Offsetting Derivative Assets:	Gross Amounts of Recognized Assets			Gross Amounts Offset in the CondensedConsolidated Balance Sheets			Net Amounts Presented in the CondensedConsolidated Balance Sheets
Commodity price derivative contracts	$	7,758		$	(5,810	)	$	1,948
Total derivative instruments	$	7,758		$	(5,810	)	$	1,948
Offsetting Derivative Liabilities:	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts Presented in the Condensed Consolidated Balance Sheets(1)
Commodity price derivative contracts	$	(46,238	)	$	5,810		$	(40,428	)
Total derivative instruments	$	(46,238	)	$	5,810		$	(40,428	)

⁽¹⁾  Included in liabilities subject to compromise in the accompanying condensed consolidated balance sheets as of March 31, 2019.

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	December 31, 2018
Offsetting Derivative Assets:	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts Presented in the Condensed Consolidated Balance Sheets
Commodity price derivative contracts	$	22,361		$	(9,308	)	$	13,053
Total derivative instruments	$	22,361		$	(9,308	)	$	13,053
Offsetting Derivative Liabilities:	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts Presented in the Condensed Consolidated Balance Sheets
Commodity price derivative contracts	$	(15,791	)	$	9,308		$	(6,483	)
Total derivative instruments	$	(15,791	)	$	9,308		$	(6,483	)

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. As previously discussed, all of our counterparties were participants in our Successor Credit Facility (see Note 6, “Debt” for further discussion), which is secured by our oil and natural gas properties; therefore, we were not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $7.8 million at March 31, 2019. We minimize the credit risk related to derivative instruments by: (i) entering into derivative instruments with counterparties that are also lenders in our Successor Credit Facility, and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.

Changes in fair value of our commodity derivatives for the periods indicated are as follows (in thousands):

	Three Months Ended March 31, 2019			Year Ended December 31, 2018
Derivative asset (liability) at beginning of period, net	$	6,570		$	(64,437	)
Purchases
Net losses on commodity and interest rate derivative contracts	(61,139		)	(9,259		)
Settlements
Cash settlements paid on matured commodity derivative contracts	16,089			80,266
Derivative asset (liability) at end of period, net	$	(38,480	)	$	6,570

8.  Fair Value Measurements

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

	March 31, 2019
	Fair Value Measurements			Assets/Liabilities
	Using Level 2			at Fair Value
Assets:
Commodity price derivative contracts	$	1,948		$	1,948
Total derivative instruments	$	1,948		$	1,948
Liabilities:
Commodity price derivative contracts	$	(40,428	)	$	(40,428	)
Total derivative instruments	$	(40,428	)	$	(40,428	)

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	December 31, 2018
	Fair Value Measurements			Assets/Liabilities
	Using Level 2			at Fair Value
Assets:
Commodity price derivative contracts	$	13,053		$	13,053
Total derivative instruments	$	13,053		$	13,053
Liabilities:
Commodity price derivative contracts	$	(6,483	)	$	(6,483	)
Total derivative instruments	$	(6,483	)	$	(6,483	)

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

The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the three months ended March 31, 2019, we incurred impairment charges of $0.4 million as oil and natural gas properties with a net cost basis of $1.1 million were written down to their fair value of $0.7 million. During the three months ended March 31, 2018, we incurred impairment charges of $14.6 million as oil and natural gas properties with a net cost basis of $73.0 million were written down to their fair value of $58.4 million. The write downs primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold and a reduction in the value of certain of our operating districts due to a decline in forward natural gas prices. In order to determine whether the carrying value of an asset is recoverable, the Company compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, the Company writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

9.  Asset Retirement Obligations

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

Asset retirement obligation at January 1, 2018	$	157,424
Liabilities added during the current period	610
Accretion expense	9,295
Liabilities related to assets divested	(16,687		)
Retirements	(2,499		)
Change in estimate	(4,935		)
Asset retirement obligation at December 31, 2018	143,208
Liabilities added during the current period	65
Accretion expense	2,180
Liabilities related to assets divested	(294		)
Retirements	(118		)
Asset retirement obligation at March 31, 2019	145,041
Less: current obligations	(4,426		)
Long-term asset retirement obligation at March 31, 2019	$	140,615

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Inputs to the valuation of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability include: (i) estimated plug and abandonment cost per well based on our experience; (ii) estimated remaining life per well based on average reserve life per field; (iii) our credit-adjusted risk-free interest rate and (iv) the average inflation factor. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are sensitive and subject to change. During the year ended December 31, 2018, we used credit-adjusted risk-free interest rate ranging between 6.5% and 7.1%; and the average inflation factor of 1.7%. During the three months ended March 31, 2019, our credit-adjusted risk-free interest rate was 6.8% and the average inflation factor was 1.6%.

10. Leases

We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets and, as result of the 2019 Chapter 11 Cases, the lease liabilities are included in liabilities subject to compromise on our consolidated balance sheets. Operating leases with lease term of 12 months or less are not capitalized and excluded from operating lease ROU assets. The lease payments are expensed on a straight-line basis over the term of the lease. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. We do not have any variable lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

We lease certain real estate, well equipment, vehicles, and information technology equipment. For certain well equipment, real-estate, and vehicle leases we account for the lease and non-lease components as a single lease component, although generally these may be accounted for separately if deemed significant.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 10 years or more. The exercise of lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise.

The components of lease expense for the three months ended March 31, 2019 were as follows (in thousands):

		Three Months Ended
Lease Expense	Classification	March 31, 2019
Assets
Short-term lease cost	Selling, general and administrative expenses or Lease operating expenses	295
Operating lease cost	Selling, general and administrative expenses or Lease operating expenses	851
Finance lease cost
Amortization of lease assets	Depreciation, depletion, amortization and accretion	1,333
Interest on lease liabilities	Interest expense	137
Net lease cost		$	2,616

Information regarding our lease terms and discount rates as of March 31, 2019 were as follows:

	March 31, 2019
Weighted-average remaining lease term (years)
Operating leases	5.7
Finance leases	1.9
Weighted-average discount rate
Operating leases	18.6	%
Finance leases	5.5	%

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Supplemental balance sheet information related to leases as of March 31, 2019 was as follows:

Leases (in thousands)	Classification	March 31, 2019
Assets
Operating lease assets	Lease assets	$	6,272
Finance lease assets, at cost	Lease assets	10,564
Accumulated amortization	Lease assets	(1,333		)
Finance lease assets, net	Lease assets	9,231
Total lease assets		$	15,503
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,466
Finance	Liabilities subject to compromise	5,099
Long-Term
Operating	Liabilities subject to compromise	5,255
Finance	Liabilities subject to compromise	4,234
Total lease liabilities		$	16,054

The maturity of our lease liabilities as of March 31, 2019 were as follows (in thousands):

	Operating Leases			Finance Leases			Total
2019 (remaining of year)	$	2,059		$	4,113		$	6,172
2020	1,772			4,400			6,172
2021	1,563			1,320			2,883
2022	1,255			30			1,285
2023	1,247			—			1,247
Thereafter	3,150			—			3,150
Total undiscounted lease liability	11,046			9,863			20,909
Imputed interest	(4,325		)	(530		)	(4,855		)
Total discounted liability	$	6,721		$	9,333		$	16,054

Supplemental cash flow and other information related to leases for the three months ended March 31, 2019 was as follows (in thousands):

	Three Months Ended
	March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,045
Operating cash flows from finance leases	$	137
Financing cash flows from finance leases	$	1,231

Rent expense for our office leases was $0.5 million for the three months ended March 31, 2018. The rent expense was for the lease of our office space in Houston, Texas as well as office leases in our other operating areas. Prior to the adoption of ASU No. 2016-02, our policy was to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease.

11. Commitments and Contingencies

Lease Commitments

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As of December 31, 2018, the minimum contractual obligations under our lease commitments were approximately $9.2 million in the aggregate. Please see Note 10, “Leases,” for a detailed discussion of our current accounting for leases with the adoption of ASU 2016-02.

	Lease Payments
	(in thousands)
2019	$	1,211
2020	1,149
2021	1,169
2022	1,204
2023	1,241
Thereafter	3,262
Total	$	9,236

Transportation Demand Charges

As of March 31, 2019, we have a contract that provides firm transportation capacity on pipeline systems. The remaining term on this contract is approximately one year and requires us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.

The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of March 31, 2019. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.

	March 31, 2019
	(in thousands)
April 1, 2019 - December 31, 2019	615
2020	410
Total	$	1,025

Development Commitments

We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. As of March 31, 2019, total estimated costs to be spent in 2019 is approximately $12.0 million, of which $5.0 million relates to our drilling and completion commitments in the Pinedale field in the Green River Basin.

Legal Proceedings

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

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

Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed, subject to reinstatement when either the

Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 3, “2019 Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases.

12.  Stockholders’ Equity

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Warrant Agreement

On August 1, 2017, the Company entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued: (i) to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), (B) 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and (C) 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with the Series A Preferred Units and Series B Preferred Units, the “Preferred Units”), three and a half year warrants (the “Preferred Unit Warrants”), which are exercisable to purchase up to 621,649 shares of Common Stock; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which are exercisable to purchase up to 640,876 shares of Common Stock. The expiration date of the Warrants is February 1, 2021. The strike price for the Preferred Unit New Warrants is $44.25, and the strike price for the Common Unit New Warrants is $61.45. As set forth above, the 2019 Plan does not contemplate providing a recovery to any holders of current equity, including the Warrants.

Earnings Per Share/Unit

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

The diluted earnings per share calculation for the three months ended March 31, 2019 and 2018 excluded 301,065 RSUs and 173,629 RSUs, respectively, and approximately 1.3 million warrants for each of the period, that were antidilutive as we were in a loss position.

13. Share-Based Compensation

The following table summarizes our time-based RSUs as of March 31, 2019:

	Time-Based Restricted Stock Units		Weighted Average Grant Date Fair Value
Non-vested at December 31, 2018	244,496		$	16.62
Vested	(1,473	)	$	11.99
Non-vested at March 31, 2019	243,023		$	16.65

We expense time-based RSUs on a straight-line basis over the requisite service period. As of March 31, 2019, the total remaining unearned compensation related to non-vested time-based RSUs was $3.1 million, which will be amortized over the weighted-average remaining service period of 1.7 years.

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

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

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	TSR Performance RSU Replacement Awards
Modification date	September 11, 2018
Remaining performance period	2.31 years
VNR closing price	$5.40
VNR beginning TSR price	$19.00
Compounded risk-free interest rate (2.31-yr)	2.75%
VNR historical volatility (2.31-yr)	71.69%
Fair value of unit	$19.76

We recognize compensation expense on a straight-line basis over the requisite service period. As of March 31, 2019, total remaining unearned compensation related to TSR performance RSUs was $1.0 million, which will be amortized over the weighted-average remaining service period of 1.8 years.

Our condensed consolidated statements of operations reflect non-cash compensation related to our MIP of $0.6 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively.

14.  Income Taxes

For the three months ended March 31, 2019, we recorded no income tax expense or benefit. The difference between our effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the three months ended March 31, 2019, the Company has continued to record a full valuation allowance against its deferred tax position. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets will be realized.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2019 and 2018, and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report and with our 2018 Annual Report.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “Forward-Looking Statements.”

Overview

We are an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. We are currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of March 31, 2019, we own properties and oil and natural gas reserves primarily located in nine operating 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.

As of March 31, 2019, based on internal reserve estimates, our total estimated proved reserves were 1,015.8 Bcfe, of which approximately 64% were natural gas reserves, 20% were oil reserves and 16% were NGLs reserves. All of our estimated reserves were classified as proved developed. As of December 31, 2018, the Company removed all proved undeveloped reserves from its total proved reserve estimate due to uncertainty regarding the availability of capital that would be required to develop the proved undeveloped reserves. Also, at March 31, 2019, we owned working interests in 10,226 gross (3,576 net) productive wells. Our operated wells accounted for approximately 60% of our total estimated proved reserves at March 31, 2019. Our average net daily production for the three months ended March 31, 2019 and the year ended December 31, 2018 was 297 MMcfe/day and 346 MMcfe/day, respectively.

We develop an annual capital expenditures budget which is reviewed and approved by our Board of Directors (the “Board”) and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities, and strategic joint ventures, when establishing our capital expenditure budget.

Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control; however, we have historically employed commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow. As a result of our defaults under our debt agreements and our 2019 Bankruptcy Petitions (as defined below), we were in default under our derivative contracts. In addition, our derivative contract counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the 2019 Debtors (as defined below) as a result of such terminations, in

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accordance with the terms of the agreements governing such derivative contracts. In April 2019, our derivative contract counterparties unilaterally terminated all derivative contracts to which we were a party.

Bankruptcy Proceedings under Chapter 11

2019 Chapter 11 Proceedings

On March 31, 2019 (the “2019 Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “2019 Debtors”) filed voluntary petitions for relief (collectively, the “2019 Bankruptcy Petitions” and, the cases commenced thereby, the “2019 Chapter 11 Cases”) under Chapter 11 of title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The 2019 Debtors are being jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

Plan Support Agreement

On May 8, 2019, the 2019 Debtors entered into the Plan Support Agreement with (a)  the RBL Lenders constituting over 66 2/3% in amount and over 50.1% in number of the revolving credit facility claims and over 66 2/3% in amount and over 50.1% in number of those certain secured swap claims, in each case under the Successor Credit Facility; and (b) the Term Loan Lenders, constituting over 66 2/3% in amount and over 50.1% in number of the Term Loan Claims.

The Plan Support Agreement sets forth, subject to certain conditions, the commitment of the 2019 Debtors and the Plan Support Parties to support the Restructuring Transactions. The Restructuring Transactions will be effectuated through the 2019 Plan.

The Restructuring Transactions will be financed by (i) the issuance of the New Common Stock; (ii) the issuance of the New Preferred Equity Class A Stock; (iii) potentially the issuance of the New Preferred Equity Class B Stock; (iv) the Exit RBL/Term Loan A Facility; and (v) the Exit Term Loan B Facility. The material terms of the Exit Facilities will be filed in advance of the hearing to consider confirmation of the 2019 Plan.

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 relief requested in the DIP Motion was approved by the Bankruptcy Court on April 30, 2019.

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.

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 absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common stock can receive any distribution or retain any property under a plan of reorganization. The 2019 Plan currently does not contemplate providing any economic recovery to holders of our existing common stock. The ultimate recovery to creditors, if

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any, will not be determined until confirmation and implementation of the 2019 Plan. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors. Our Plan could result in any of the holders of our liabilities receiving no distribution on account of their interests and cancellation of their holdings. Moreover, the 2019 Plan can be confirmed, under the Bankruptcy Code even though the 2019 Plan provides that the holders of our common stock receive no distribution on account of their equity interests. Please read Note 3, “2019 Chapter 11 Proceedings” of the Notes to the Condensed Consolidated Financial Statements 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 Part I - Item 1A, Risk Factors in our 2018 Annual Report and in Part II - Item 1A, Risk Factors in this Quarterly Report. Because of these risks and uncertainties, the description of our operations, properties and capital plans included in our 2018 Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Capital Development

Total capital expenditures were approximately $11.0 million during the three months ended March 31, 2019. Subject to the satisfaction of the conditions under the Final Dip Order and DIP Credit Agreement, we currently anticipate a total capital expenditures budget ranging from $43.0 million to $50.0 million for the full year of 2019. We have reduced our capital expenditures budget for 2019 primarily due to less drilling activity in the Pinedale Basin. During the three months ended March 31, 2019, we participated in the drilling of 41 gross (6.4 net) non-operated wells and in the completion of 16 gross (1.3 net) non-operated wells.

In the Arkoma Basin we expect to spend between $7.0 million and $8.0 million for the remainder of 2019 where we will be participating as a non-operated partner with Encana Corporation in a one rig program, drilling and completing horizontal Woodford wells. This program is a continuation of our 2018 one rig program with Newfield Exploration Company. In the Green River Basin, we are on track to spend between $3.0 million and $6.0 million in the Pinedale Field in Wyoming for the remainder of 2019, where we participate in the drilling of vertical natural gas wells with partners Ultra Petroleum Corporation and Pinedale Energy Partners. In addition to our drilling and completion programs, we expect to spend approximately $6.0 million to $8.0 million for the remainder of 2019 on other uplift projects, primarily in the Permian New Mexico Red Lake field, as we continue our successful 2018 operated Yeso recompletion and commingle program. The remaining $16.0 to $17.0 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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Results of Operations

The following table sets forth selected financial and operating data for the periods indicated (in thousands):

	Three Months Ended
	March 31,
	2019 (a)			2018
Revenues:
Oil sales	$	32,748		$	46,111
Natural gas sales	62,314			55,267
NGLs sales	14,048			21,897
Oil, natural gas and NGLs sales	109,110			123,275
Net losses on commodity derivative contracts	(61,139		)	(18,585		)
Total revenues and losses on commodity derivative contracts	$	47,971		$	104,690
Costs and expenses:
Production:
Lease operating expenses	26,247			30,995
Transportation, gathering, processing and compression	9,522			11,502
Production and other taxes	9,823			9,781
Depreciation, depletion, amortization, and accretion	35,714			40,039
Impairment of oil and natural gas properties	438			14,601
Exploration expense	201			1,316
Selling, general and administrative expenses	11,966			12,240
Non-cash compensation	591			496
Total costs and expenses	$	94,502		$	120,970
Other income (expense):
Interest expense	$	(16,975	)	$	(14,753	)
Net losses on divestitures of oil and natural gas properties	(458		)	—
Other	87			149
Reorganization items	(18,388		)	(1,707		)

(a) During the three months ended March 31, 2019, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

Revenues

Oil, natural gas and NGLs sales were $109.1 million and $123.3 million for the three months ended March 31, 2019 and 2018 respectively. The key oil, natural gas and NGLs revenue measurements were as follows:

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	Three Months Ended
	March 31,
	2019 (a)		2018
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	55.76	$	55.30
Natural Gas (Price/Mcf)	$	3.23	$	2.36
NGLs (Price/Bbl)	$	21.53	$	27.91
Average realized prices, including hedges:
Oil (Price/Bbl)	$	48.82	$	41.66
Natural Gas (Price/Mcf)	$	2.45	$	2.63
NGLs (Price/Bbl)	$	26.08	$	22.78
Average NYMEX prices:
Oil (Price/Bbl)	$	55.42	$	62.89
Natural Gas (Price/Mcf)	$	3.16	$	2.98
Total production volumes:
Oil (MBbls)	587		834
Natural Gas (MMcf)	19,299		23,371
NGLs (MBbls)	652		785
Combined (MMcfe)	26,737		33,081
Average daily production volumes:
Oil (Bbls/day)	6,525		9,266
Natural Gas (Mcf/day)	214,439		259,674
NGLs (Bbls/day)	7,248		8,717
Combined (Mcfe/day)	297,078		367,568

(a) During the three months ended March 31, 2019, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

The decrease in oil and NGLs sales during the three months ended March 31, 2019 compared to the same period in 2018 was primarily due to a decrease in average daily production. For the three months ended March 31, 2019, average daily production was approximately 6,525 Bbls/day for oil and 7,248 Bbls/day for NGLs compared to 9,266 Bbls/day for oil and 8,717 Bbls/day for NGLs for same period in 2018. The decrease in average daily production was a result of divestitures completed during the last nine months of 2018 and the three months ended March 31, 2019.

The decrease in total commodity sales which resulted from lower average daily production for all products was partially offset by an increase in average realized natural gas price, excluding hedges, primarily due to a higher average NYMEX natural gas price during the three months ended March 31, 2019, which increased 6%, as compared to the same period in 2018.

On a Mcfe basis, crude oil, natural gas and NGLs accounted for 13%, 72% and 15%, respectively, of our production during the three months ended March 31, 2019 compared to 15%, 71% and 14% respectively, of our production during the same period in 2018.

Hedging and Price Risk Management Activities

We recognized a net loss on commodity derivative contracts of $61.1 million and $18.6 million during the three months ended March 31, 2019 and 2018, respectively. 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 we pay 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

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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 condensed 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 condensed 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. In April 2019, all our commodity derivative contracts were terminated and the net settlement owed to counterparties amounted to $53.9 million.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and other customary charges. Lease operating expenses were $26.2 million and $31.0 million for the three months ended March 31, 2019 and 2018, 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 2018 and the three months ended March 31, 2019. Overall, spending during the three months ended March 31, 2019 decreased as compared to the three months ended March 31, 2018 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 accounted for under ASC Topic 606 where we have concluded we are the principal and the ultimate third party is our customer. We recognize revenue related to these contracts on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in our condensed consolidated statement of operations. These expenses were $9.5 million for the three months ended March 31, 2019, which represents a decrease from the $11.5 million recorded during the three months ended March 31, 2018 primarily due to lower NGLs sales.

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 or county and are based on the value of our reserves. As a percentage of wellhead revenues, production and other taxes was 9.0% and 7.9% for the three months ended March 31, 2019 and 2018, respectively. The tax rates were higher during first three months of 2019 compared to the same period in 2018 due to lower allowable deductions.

Depreciation, depletion, amortization, and accretion expense was $35.7 million and $40.0 million for the three months ended March 31, 2019 and 2018, respectively. The decrease in depreciation, depletion, amortization, and accretion expense is due to a lower amortization base as a result of the divestitures completed during 2018 and the three months ended March 31, 2019. 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.

An impairment of oil and natural gas properties of $0.4 million and $14.6 million was recognized during the three months ended March 31, 2019 and 2018, respectively. The impairment charge recognized during the three months ended March 31, 2018 related to downward revisions in our unproved property leasehold acreage and working interest in certain of our undeveloped leasehold.

Exploration expense decreased from $1.3 million during the three months ended March 31, 2018 to $0.2 million for the three months ended March 31, 2019 as a result of a reduction in exploration activities.

Selling, general and administrative expenses (excluding non-cash compensation) include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. During the three months ended March 31, 2019 and 2018, selling, general and administrative expenses were $12.0 million and $12.2 million, respectively. The decrease is primarily due to management severance payments made during the three months ended March 31, 2018, offset by increased professional fees during the three months ended March 31, 2019 as a result of management consulting efficiency initiatives. In addition, we incurred non-cash compensation expense of $0.6 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively.

Other Income and Expense

Interest expense was $17.0 million and $14.8 million during the three months ended March 31, 2019 and 2018, respectively. The increase in interest expense was primarily due to higher interest rates.

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During the three months ended March 31, 2019, the Company recorded a net loss of approximately $0.5 million on the sale of oil and natural gas properties.

Reorganization Items

We incurred reorganization costs of $18.4 million and $1.7 million for the three months ended March 31, 2019 and 2018, respectively. Reorganization items include expenses, gains and losses that are the result of the reorganization and restructuring of the business.

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 production and development of oil and natural gas properties. Our future success in growing reserves, production and cash flow after emergence from bankruptcy 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. 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 relief requested in the DIP Motion was approved by the Bankruptcy Court on April 30, 2019. 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 $32.0 million of cash on hand as of May 10, 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 satisfaction of the conditions under the Final Dip Order and DIP Credit Agreement, the Company will have further liquidity of $45.0 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 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.

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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

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”);

• proceeds of the New Money Facility may be used by the DIP Borrower to (i) pay certain costs and expenses related to the 2019 Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;

• the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of (a) nine months after the 2019 Petition Date, (b) the consummation of a sale of all or substantially all of the equity and/or assets of the DIP Borrower and its subsidiaries, (c) the occurrence of an event of default (subject to any cure periods), and (d) the effective date of a plan of reorganization in the 2019 Chapter 11 Cases.

• interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%, or the adjusted base rate plus 4.50% per annum;

• in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the New Money Facility, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;

• the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;

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

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

The relief requested in the DIP Motion was approved by the Bankruptcy Court on April 30, 2019.

Statements of Cash Flows

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The following table summarizes our primary sources and uses of cash for the periods indicated (in thousands):

	Three Months Ended
	March 31,
	2019			2018
Net cash provided by (used in) operating activities	$	(16,330	)	$	36,249
Net cash used in investing activities	$	(6,615	)	$	(44,115	)
Net cash provided by (used in) financing activities	$	(5,781	)	$	13,236

Cash Flow from Operations

Net cash used in operating activities was approximately $16.3 million for the three months ended March 31, 2019 compared to net cash provided by operating activities of $36.2 million for the three months ended March 31, 2018. Changes in working capital decreased total cash flows by $23.5 million for the three months ended March 31, 2019, and increased total cash flows by $3.7 million for the three months ended March 31, 2018. Contributing to the decrease in working capital during the first three months of 2019 was a decrease in accounts payable, oil and natural gas revenue payable and accrued expenses and other current liabilities that resulted primarily from the timing effects of payments. Also contributing to the decrease in working capital was the increase in other current assets and other assets, offset by a decrease in accounts receivable related to the timing of receipts from production.

During the first quarter of 2018, the increase in working capital resulted from a $13.9 million decrease in accounts receivable related to the timing of receipts from production, offset by a $9.5 million decrease in accounts payable, oil and natural gas revenue payable and accrued expenses and other current liabilities that resulted primarily from the timing effects of payments.

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 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 received for production. We enter into derivative contracts to reduce the impact of commodity price volatility on operations. We primarily use fixed-price swaps, collars, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. See Note 7 of the Notes to the Condensed Consolidated Financial Statements, included under Part I, Item 1 of this Quarterly Report for further discussion.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $6.6 million for the three months ended March 31, 2019 compared to approximately $44.1 million for the three months ended March 31, 2018. Net cash used in investing activities during the first three months of 2019 primarily included $4.0 million for the drilling and development of oil and natural gas properties and $7.0 million for deposits and prepayments related to the drilling and development of oil and natural gas properties, offset by $4.5 million in proceeds from the sale of oil and natural gas properties.

During the first three months of 2018, we spent $23.3 million for drilling and development of oil and natural gas properties and $20.8 million for deposits and prepayments related to the drilling and development of oil and natural gas properties.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $5.8 million for the three months ended March 31, 2019 compared to net cash provided by financing activities of approximately $13.2 million for the three months ended March 31, 2018. Net cash used in financing activities during the three months ended March 31, 2019 included repayments of debt of $5.8 million. During the three months ended March 31, 2018, cash provided by financing activities included proceeds from our revolving credit facility of $48.0 million, offset by repayments of our revolving credit facility and term loan of $34.6 million.

Debt and Credit Facilities

Acceleration of Debt Obligations

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As of December 31, 2018, the Company was not in compliance with certain covenants under the Successor Credit Facility (defined herein). Accordingly, all amounts due under the Successor Credit Facility and New Notes (defined herein) (collectively, the “Debt Instruments”) are classified as current in the accompanying consolidated balance sheet as of that date. The commencement of the 2019 Chapter 11 Cases is an event of default that accelerated the 2019 Debtors’ obligations under these Debt Instruments. As of March 31, 2019, amounts outstanding under the Debt instruments are included in liabilities subject to compromise in the condensed consolidated balance sheet. Any efforts to enforce such obligations under the Debt Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code. Further, in accordance with accounting guidance in ASC 852, we will not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases.

Successor Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “Successor Credit Facility”), the lenders party thereto agreed to provide VNG with an $850.0 million senior secured reserve-based revolving credit facility (the “Revolving Loan”). The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). As of March 31, 2019, the Successor Credit Facility had a borrowing base of $677.9 million.

As discussed in Note 5, “Divestitures,” the net cash proceeds received from the sale of properties of $4.4 million were used to pay down debt. At March 31, 2019, there were $677.7 million of outstanding borrowings under the Successor Credit Facility.

New Notes

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes”) to certain eligible holders of the Predecessor’s second lien notes (the “Existing Notes”) in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders.

Please refer to Note 6 of the Notes to the Condensed Consolidated Financial Statements included under Part I, Item 1of this Quarterly Report for further information regarding our debt.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States (“GAAP”) requires management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

The most significant areas involving management judgments and estimates may be found in our 2018 Annual Report, in the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” There have been no material changes to our critical accounting policies as compared to the critical accounting policies described in our 2018 Annual Report, other than our accounting policy on Leases.

For periods subsequent to filing the 2019 Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Use of Estimates

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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 and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization, and accretion expense, income taxes, and non-cash compensation. Actual results could differ from those estimates.

Off-Balance Sheet Arrangements

We currently do not have off-balance sheet arrangements.

Non-GAAP Financial Measure

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 is defined as net income (loss) attributable to Vanguard stockholders/unitholders plus:

• Net income 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:

• Interest expense;

• Depreciation, depletion, amortization, and accretion;

• Impairment of oil and natural gas properties;

• Exploration expense;

• Change in fair value of commodity derivative contracts;

• Net loss on divestitures of oil and natural gas properties;

• Compensation related items, which include share-based compensation expense;

• Reorganization items;

• 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 (loss), 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.

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Adjusted EBITDA attributable to Vanguard stockholders/unitholders for the three months ended March 31, 2019 was $36.3 million compared to $52.0 million for the three months ended March 31, 2018. The following table presents a reconciliation of consolidated net loss to Adjusted EBITDA (in thousands):

	Three Months Ended
	March 31,
	2019			2018
Net loss attributable to Vanguard stockholders	$	(82,265	)	$	(32,684	)
Add: Net income attributable to non-controlling interests	—			93
Net loss	$	(82,265	)	$	(32,591	)
Plus:
Interest expense	16,975			14,753
Depreciation, depletion, amortization, and accretion	35,714			40,039
Impairment of oil and natural gas properties	438			14,601
Exploration expense	201			1,316
Change in fair value of commodity derivative contracts(a)	45,050			9,293
Net loss on divestitures of oil and natural gas properties	458			—
Compensation related items	591			496
Reorganization items	18,388			1,707
Severance costs	788			2,256
Material costs incurred on strategic transactions	—			148
Adjusted EBITDA before non-controlling interest	36,338			52,018
Adjusted EBITDA attributable to non-controlling interest	—			(37		)
Adjusted EBITDA attributable to Vanguard stockholders	$	36,338		$	51,981

(a) These items are included in the net gains (losses) on commodity derivative contracts line item in the condensed consolidated statements of operations as follows:

	Three Months Ended
	March 31,
	2019			2018
Net cash settlements paid on matured commodity derivative contracts	$	(16,089	)	$	(9,292	)
Change in fair value of commodity derivative contracts	(45,050		)	(9,293		)
Net losses on commodity derivative contracts	$	(61,139	)	$	(18,585	)

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Item 3. 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 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) promulgated under 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) promulgated under the Exchange Act) as of the end of the period covered by this Quarterly 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 or submit 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 SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2019 at the reasonable assurance level.     

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the first quarter of 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

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

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

Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed, subject to reinstatement when either the

Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 3. 2019 Chapter 11 Proceedings under Item 1.

Unaudited Consolidated Financial Statements, for information regarding our Chapter 11 Cases.

Item 1A.  Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our securities, please refer to Part I-Item 1A-Risk Factors in our 2018 Annual Report. There have been no material changes to the risk factors set forth in our 2018 Annual Report, except for the following:

The Plan Support Agreement is subject to significant conditions and milestones that may be difficult for us to satisfy.

There are certain material conditions we must satisfy under the Plan Support Agreement, including the timely satisfaction of milestones in the anticipated 2019 Chapter 11 Cases, such as confirmation of a Chapter 11 plan of reorganization, and effectiveness of such plan. Our ability to timely complete such milestones is subject to risks and uncertainties that may be beyond our control.

If the Plan Support Agreement is terminated, our ability to confirm and consummate a Chapter 11 plan of reorganization could be materially and adversely affected.

The Plan Support Agreement contains a number of termination events, upon the occurrence of which certain parties to the Plan Support Agreement may terminate the agreement. If the Plan Support Agreement is terminated, each of the parties thereto will be released from their obligations in accordance with the terms of the Plan Support Agreement except as otherwise set forth therein. Such termination may result in the loss of support for a Chapter 11 plan of reorganization by the parties to the Plan Support Agreement, which could adversely affect our ability to confirm and consummate the 2019 Plan. Furthermore, if the Plan Support Agreement is terminated, any exit financing upon emergence from the 2019 Chapter 11 Cases will be subject to the approval of the Administrative Agent in all respects.

During the existence of an event of default and the 2019 Chapter 11 Cases, we have no borrowing capacity under our Successor Credit Facility.

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. There can be no assurance that the 2019 Plan as outlined in the Plan Support Agreement (or any other plan of reorganization) will be confirmed by the Bankruptcy Court and consummated.

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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.  Defaults Upon Senior Securities

As described herein, the commencement of the 2019 Chapter 11 Cases constituted an event of default that accelerated our obligations under the Debt Instruments. Please see Note 3, “2019 Chapter 11 Proceedings” under Item 1. Unaudited Consolidated Financial Statements.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

Item 6.  Exhibits

Each exhibit identified below is filed as a part of this Report.

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)
10.1	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)
10.2	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)
10.3	Employment Agreement with 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)
10.4	Vanguard Natural Resources, Inc. 2019 Short Term Incentive Plan (incorporated by reference to Exhibit 10.21 to our Annual Report on Form 10-K for the year ended December 31, 2018, filed on April 15, 2019)
10.5	Vanguard Natural Resources, Inc. 2019 Incentive Plan (incorporated by reference to Exhibit 10.22 to our Annual Report on Form 10-K for the year ended December 31, 2018, filed on April 15, 2019)
10.6	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 (incorporated by reference to Exhibit 10.23 to our Annual Report on Form 10-K for the year ended December 31, 2018, filed on April 15, 2019)
10.7	First Amendment to Debtor-in-Possession Credit Agreement, dated as of April 29, 2019, among Vanguard Natural Gas, LLC, the Guarantors party thereto, the Administrative Agent, the Existing Lender and the New Lenders (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed May 3, 2019).
10.8	Plan Support Agreement, dated as of May 8, 2019, among the 2019 Debtors and the Plan Support Parties (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed May 13, 2019)
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 1350 Certification of Chief Executive Officer
32.2**	Section 1350 Certification of Chief Financial Officer

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Exhibit Number	Description of Exhibit
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document

_______________

* Provided herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements 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.

	VANGUARD NATURAL RESOURCES, INC.
	(Registrant)
Date: May 15, 2019	/s/ Ryan Midgett
	Ryan Midgett
	Chief Financial Officer
	(Principal Financial Officer and Authorized Officer)

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