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
	For the quarterly period ended June 30, 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~~000-~~33756~~55826

~~Vanguard~~Grizzly ~~Natural Resources~~Energy, ~~Inc.~~LLC

(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)

Vanguard Natural Resources, Inc.

(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~~

AsTitle of ~~May 10,~~each ~~2019,~~class ~~the~~Ticker ~~registrant~~symbol(s) ~~had~~Name ~~20,124,080~~of ~~outstanding~~each ~~shares~~exchange ofon ~~common~~which ~~stock,~~registered ~~$0.001~~— ~~par~~— ~~value.~~—

~~VANGUARD~~As ~~NATURAL~~of ~~RESOURCES~~August 16, ~~INC.~~2019, ~~AND~~the ~~SUBSIDIARIES~~registrant had 100,000 outstanding Series C common units, 45,738,661 outstanding Series A preferred units and 861,252 outstanding Series B preferred units.

GRIZZLY ENERGY, LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

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	2928
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4143
Item 4.	Controls and Procedures	4143
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4244
Item 1A.	Risk Factors	4244
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4346
Item 3.	Defaults Upon Senior Securities	4346
Item 4.	Mine Safety Disclosures	4347
Item 5.	Other Information	4347
Item 6.	Exhibits	4348

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~~Grizzly” are to ~~Vanguard~~Grizzly ~~Natural Resources~~Energy, ~~Inc.,~~LLC (formerly known as ~~VNR~~Vanguard ~~Finance~~Natural ~~Corp.~~Resources, Inc.) and its subsidiaries, including Grizzly Natural Gas, LLC (formerly known as Vanguard Natural Gas, LLC) (“~~VNG~~GNG”), Grizzly Energy Holdco, Inc., Grizzly Energy Holdings, LLC (formerly known as VNR Holdings, LLC) (“~~VNRH~~GEH”), Grizzly Operating, LLC (formerly known as Vanguard Operating, LLC) (“VOGO”), Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Grizzly Energy Acquisition Co., LLC (formerly known as Eagle Rock Energy Acquisition Co., Inc.) (“~~ERAC~~GAC”), Grizzly Upstream Development Co., LLC (formerly known as Eagle Rock Upstream Development Co., Inc.) (“~~ERUD~~GUD”), Grizzly Acquisition Partnership, LLC (formerly known as Eagle Rock Acquisition Partnership, L.P.) (“~~ERAP~~GAP”), Grizzly Energy Acquisition Co. II, LLC (formerly known as Eagle Rock Energy Acquisition Co. II, Inc.) (“~~ERAC~~GAC II”), Grizzly Upstream Development Co. II, LLC (formerly known as Eagle Rock Upstream Development Co. II, Inc.) (“~~ERUD~~GUD II”) and Grizzly Acquisition Partnership II, LLC (formerly known as Eagle Rock Acquisition Partnership II, L.P.) (“~~ERAP~~GAP II”).

References in this report to “us,” “we,” “our” or the “~~Predecessor~~Company” ~~are~~or like terms refer to (i) Vanguard Natural Resources, ~~LLC~~Inc. for the period prior to emergence from the Chapter 11 bankruptcy cases on July 16, ~~individually~~2019 (the “Effective Date”) and ~~collectively~~(ii) ~~with~~Grizzly ~~its~~Energy, ~~subsidiaries~~LLC for the period as of and following the Effective Date.

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”), our Quarterly Report on Form 10-Q for the three months ended March 31, 2019 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~~grizzlyenergyllc.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 achieve the anticipated benefits from the consummation of the Chapter 11 Cases (as defined herein);


•	our ability to execute our business strategies, including our business strategies following emergence from the Chapter 11 Cases;


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

• ~~our~~the ~~ability~~potential toadverse ~~access~~effects of the ~~public~~consummation ~~capital~~of ~~markets~~the Plan (as defined herein) on our liquidity and results of operations;

• ~~risks~~the ~~and~~impact ~~uncertainties~~of ~~associated with~~ the ~~2019~~ Chapter 11 Cases ~~(as~~on ~~defined~~the ~~herein)~~liquidity ~~described~~and ~~below,~~market ~~including~~price of our ~~inability~~units toand ~~confirm~~on ~~and~~our ~~consummate~~ability ~~the~~to ~~2019~~access ~~Plan~~the ~~(as~~public ~~defined~~capital ~~herein)~~markets;

• ~~inability~~ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our ~~2019~~ Bankruptcy Petitions (as defined herein) and following emergence from the Chapter 11 Cases;

• ~~our ability to obtain~~ the ~~approval~~effects of the Bankruptcy ~~Court~~Petitions ~~(as~~on ~~defined~~the ~~herein)~~Company ~~with~~and ~~respect~~on tothe ~~motions~~interests orof ~~other~~various ~~requests~~constituents, ~~made~~including toholders ~~the~~of ~~Bankruptcy~~our ~~Court~~Common inand ~~the~~Preferred ~~2019~~Units ~~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~~potential ofadverse ~~time~~effects ~~that~~of the ~~Company~~consummation ~~will~~of ~~operate~~the ~~under~~ Chapter 11 ~~protection~~Cases ~~and~~on ~~the~~our ~~continued~~liquidity ~~availability~~and ofresults ~~operating capital during the pendency~~ of ~~the proceedings~~operations;

• ~~risks~~increased ~~associated~~advisory ~~with~~costs ~~third~~and ~~party~~professional ~~motions~~fees ~~in the 2019 Chapter 11 Cases, which may interfere with our ability~~ to ~~confirm~~implement ~~and~~the ~~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 critical technical personnel;


•	competition in the oil and natural gas industry;

• ~~risks~~ability ~~arising~~to ~~out~~execute ofour ~~hedging~~strategy ~~transactions~~including the divestment of assets;

• the costs and effects of litigation; and

• 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~~GRIZZLY ~~NATURAL RESOURCES~~ENERGY, ~~INC.~~LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended	~~Three Months Ended~~							Six Months Ended
		March 31,
	June 30,								June 30,
	2019	~~2019~~			2018	~~2018~~			2019			2018
Revenues:
Oil sales	$	$37,150	~~32,748~~		$	$46,503	~~46,111~~		$	69,897		$	92,614
Natural gas sales	29,132	~~62,314~~			42,623	~~55,267~~			91,446			97,890
NGLs sales	13,702	~~14,048~~			22,587	~~21,897~~			27,749			44,484
Oil, natural gas and NGLs sales	79,984	~~109,110~~			111,713	~~123,275~~			189,092			234,988
Net losses on commodity derivative contracts	(9,063	~~(61,139~~	)	)	(45,332	~~(18,585~~	)	)	(70,202		)	(63,917		)
Total revenues and losses on commodity derivative contracts	70,921	~~47,971~~			66,381	~~104,690~~			118,890			171,071
Costs and expenses:
Production:
Lease operating expenses	29,035	~~26,247~~			36,763	~~30,995~~			55,282			67,758
Transportation, gathering, processing and compression	8,484	~~9,522~~			9,768	~~11,502~~			18,006			21,270
Production and other taxes	7,833	~~9,823~~			7,971	~~9,781~~			17,656			17,752
Depreciation, depletion, amortization, and accretion	39,044	~~35,714~~			38,711	~~40,039~~			74,758			78,750
Impairment of oil and natural gas properties	323,188	~~438~~			7,552	~~14,601~~			323,626			22,153
Exploration expense	275	~~201~~			430	~~1,316~~			476			1,746
Selling, general and administrative expenses	9,238	~~12,557~~			11,108	~~12,736~~			21,795			23,844
Total costs and expenses	417,097	~~94,502~~			112,303	~~120,970~~			511,599			233,273
Loss from operations	(346,176	~~(46,531~~	)	)	(45,922	~~(16,280~~	)	)	(392,709		)	(62,202		)
Other income (expense):
Interest expense		(16,975		)		(14,753		)
Interest expense (excludes contractual interest expense of $15.7 million for each of the three and six months ended June 30, 2019)	(1,680		)		(15,870		)		(18,655		)	(30,623		)
Net loss on divestiture of oil and natural gas properties		(458		)		—
Net gain (loss) on divestitures of oil and natural gas properties	—				4,900				(458		)	4,900
Other	497	87			(175	~~149~~	)		586			(26		)
Total other expense, net	(1,183	~~(17,346~~	)	)	(11,145	~~(14,604~~	)	)	(18,527		)	(25,749		)
Loss before reorganization items	(347,359	~~(63,877~~	)	)	(57,067	~~(30,884~~	)	)	(411,236		)	(87,951		)
Reorganization items (Note 3)		(18,388		)		(1,707		)
Reorganization items (Note 2)	(24,743		)		(610		)		(43,131		)	(2,317		)
Net loss	(372,102	~~(82,265~~	)	)	(57,677	~~(32,591~~	)	)	(454,367		)	(90,268		)
Less: Net income attributable to non-controlling interests	—	—			(96	~~(93~~	)	)	—			(189		)
Net loss attributable to Common stockholders	$	$(372,102	~~(82,265~~)	)	$	$(57,773	~~(32,684~~)	)	$	(454,367	)	$	(90,457	)
Net loss per share – basic and diluted	$	$(18.49	~~(4.09~~)	)	$	$(2.87	~~(1.63~~)	)	$	(22.58	)	$	(4.50	)
Weighted average Common shares outstanding
Common shares – basic and diluted	20,124	~~20,124~~			20,100	~~20,100~~			20,124			20,100

See accompanying notes to condensed consolidated financial statements

~~VANGUARD~~GRIZZLY ~~NATURAL RESOURCES~~ENERGY, ~~INC.~~LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

(Unaudited)

	March 31, 2019			December 31, 2018
	June 30, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	544,~~512~~782		$	33,538
Trade accounts receivable, net	5542,~~119~~892			62,073
Derivative assets	~~1,948~~—			6,287
Restricted cash	34,~~750~~449			4,450
Prepaid drilling costs	124,~~519~~916			12,476
Other current assets	119,~~936~~770			5,663
Total current assets	90106,~~784~~809			124,487
Oil and natural gas properties
Proved properties	1,~~563~~574,~~760~~565			1,567,903
Unproved properties	81,~~597~~215			81,597
	1,645,357			1,649,500
	1,655,780			1,649,500
Accumulated depletion, amortization and impairment	(~~302~~661,~~521~~137		)	(269,972		)
Oil and natural gas properties, net – successful efforts	1994,~~342,836~~643			1,379,528
Other assets
Lease assets	1513,~~503~~661			—
Derivative assets	—			6,766
Other assets	1716,~~043~~422			9,321
Total assets	$	1,~~466~~131,~~166~~535		$	1,520,102
Liabilities and equity
Current liabilities
Accounts payable:
Trade	$	—4,476		$	29,709
Accrued liabilities:
Lease operating	—10,628			13,140
Developmental capital	—3,298			6,937
Interest	—330			4,999
Production and other taxes	—23,358			23,658
Other	423,~~426~~371			12,175
Derivative liabilities	—			6,483
Oil and natural gas revenue payable	—19,969			35,802
Long-term debt classified as current	—			879,181
Other current liabilities	—			9,091
Short-term debt	20,000			—
Total current liabilities	4,426			1,021,175
Other current liabilities	11,122			9,091
Long-term debt, net of current portion (Note 6)	—			5,446
Total current liabilities	116,552			1,021,175
Asset retirement obligations	140,615			139,433
Long-term debt, net of current portion (Note 5)	—			5,446
Other long-term liabilities	—			523
Asset retirement obligations	141,019			139,433
Total liabilities not subject to compromise	145,041			1,166,577
Other long-term liabilities	8,020			523
Liabilities subject to compromise (Note 3)	1,049,274			—
Total liabilities not subject to compromise	265,591			1,166,577
Total liabilities	1,194,315			1,166,577
Liabilities subject to compromise (Note 2)	965,605			—
Commitments and contingencies (Note 11)
Total liabilities	1,231,196			1,166,577
Stockholders’ equity (Note 12)
Commitments and contingencies (Note 10)
Common stock ($0.001 par value, 50,000,000 shares authorized; 20,124,080 shares issued and outstanding at March 31, 2019 and December 31, 2018)	20			20
Stockholders’ equity (deficit) (Note 11)
Additional paid-in capital	509,477			508,886
Common stock ($0.001 par value, 50,000,000 shares authorized; 20,124,081 and 20,124,080 shares issued and outstanding at June 30, 2019 and December 31, 2018, respectively)	20			20
Accumulated deficit	(237,646		)	(155,381		)
Additional paid-in capital	510,067			508,886
Total stockholders' equity	271,851			353,525
Accumulated deficit	(609,748		)	(155,381		)
Total liabilities and equity	$	1,466,166		$	1,520,102
Total stockholders’ equity (deficit)	(99,661		)	353,525
Total liabilities and equity (deficit)	$	1,131,535		$	1,520,102

See accompanying notes to condensed consolidated financial statements

~~VANGUARD~~GRIZZLY ~~NATURAL RESOURCES~~ENERGY, ~~INC.~~LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(in thousands)

(Unaudited)

	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders' Equity
	Three Months Ended June 30, 2019
	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders’ Deficit
	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
Net loss	—	—		—		(372,102		)	(372,102		)
Share-based compensation	—	—		590		—			590
Balance at June 30, 2019	20,124	$	20	$	510,067	$	(609,748	)	$	(99,661	)

	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders' Equity
	Six Months Ended June 30, 2019
	Shares	Amount
	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders’ Deficit
Balance at December 31, 2017	20,100	$	20	$	506,640	$	(111,410	)	$	2,278		$	397,528
	Shares	Amount
Net income (loss)	—	—		—		(32,684		)	93			(32,591		)
Balance at December 31, 2018	20,124	$	20	$	508,886	$	(155,381	)	$	353,525
Share-based compensation	—	—		496		—			—			496
Net loss	—	—		—		(454,367		)	(454,367		)
Potato Hills cash distribution to non-controlling interest	—	—		—		—			(177		)	(177		)
Share-based compensation	—	—		1,181		—			1,181
Balance at March 31, 2018	20,100	$	20	$	507,136	$	(144,094	)	$	2,194		$	365,256
Balance at June 30, 2019	20,124	$	20	$	510,067	$	(609,748	)	$	(99,661	)



	Three Months Ended June 30, 2018
	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders’ Equity
	Shares	Amount		Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders’ Equity
Balance at March 31, 2018	20,100	$	20	$	507,136	$	(144,094	)	$	2,194		$	365,256
Net income (loss)	—	—		—		(57,773		)	96			(57,677		)
Share-based compensation	—	—		579		—			—			579
Potato Hills cash distribution to non-controlling interest	—	—		—		—			(250		)	(250		)
Balance at June 30, 2018	20,100	$	20	$	507,715	$	(201,867	)	$	2,040		$	307,908



	Six Months Ended June 30, 2018
	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders’ Equity
	Shares	Amount		Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Stockholders’ Equity
Balance at December 31, 2017	20,100	$	20	$	506,640	$	(111,410	)	$	2,278		$	397,528
Net income (loss)	—	—		—		(90,457		)	189			(90,268		)
Share-based compensation	—	—		1,075		—			—			1,075
Potato Hills cash distribution to non-controlling interest	—	—		—		—			(427		)	(427		)
Balance at June 30, 2018	20,100	$	20	$	507,715	$	(201,867	)	$	2,040		$	307,908

See accompanying notes to condensed consolidated financial statements

~~VANGUARD~~GRIZZLY ~~NATURAL RESOURCES~~ENERGY, ~~INC.~~LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(~~unaudited~~Unaudited)

	Three Months Ended
	Six Months Ended
	March 31,
	June 30,
(in thousands)	2019			2018
Operating activities
Net loss	$	(82454,~~265~~367	)	$	(3290,~~591~~268	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	3574,~~714~~758			4078,~~039~~750
Impairment of oil and natural gas properties	~~438~~323,626			1422,~~601~~153
Amortization of deferred financing costs	~~830~~841			~~677~~1,361
Compensation related items	591			496
Share-based compensation	1,181			1,075
Net losses on commodity derivative contracts	6170,~~139~~202			1863,~~585~~917
Cash settlements paid on matured commodity derivative contracts	(169,~~089~~762		)	(927,~~292~~139		)
Net loss on divestiture of oil and natural gas properties	458			—
Net (gain) loss on divestiture of oil and natural gas properties	458			(4,900		)
Non-cash reorganization items (Note 3)	6,311			—
Non-cash reorganization items (Note 2)	20,365			—
Changes in operating assets and liabilities:
Trade accounts receivable	618,~~496~~723			1314,~~905~~124
Other current assets	(64,~~359~~158		)	(~~692~~1,357		)
Accounts payable and oil and natural gas revenue payable	(1524,~~058~~051		)	(~~3,191~~136		)
Accrued expenses and other current liabilities	(~~729~~2,666		)	(6,~~292~~598		)
Other assets	(7,~~807~~291		)	4126
Net cash provided by (used in) operating activities	(16,330		)	36,249
Net cash provided by operating activities	7,859			51,108
Investing activities
Additions to property and equipment	(3139		)	(6894		)
Additions to oil and natural gas properties	(46,~~012~~801		)	(2342,~~270~~637		)
Deposits and prepayments of oil and natural gas properties	(7,~~033~~086		)	(2049,~~777~~256		)
Proceeds from the sale of oil and natural gas properties	4,461			—59,876
Net cash used in investing activities	(69,~~615~~465		)	(4432,~~115~~111		)
Financing activities
Proceeds from long-term debt	—			4890,000
Repayment of long-term debt	(57,~~775~~145		)	(34104,~~554~~702		)
Potato Hills distribution to non-controlling interest	—			(177		)
Proceeds from debtor-in-possession financing	20,000			—
Financing fees	(6		)	(33		)
Potato Hills distribution to non-controlling interest	—			(427		)
Net cash provided by (used in) financing activities	(5,781		)	13,236
Financing fees	(6		)	(172		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(28,726		)	5,370
Net cash provided by (used in) financing activities	12,849			(15,301		)
Net increase in cash, cash equivalents and restricted cash	11,243			3,696
Cash, cash equivalents and restricted cash, beginning of period	37,988			10,017
Cash, cash equivalents and restricted cash, end of period	$	949,~~262~~231		$	1513,~~387~~713
Supplemental cash flow information:
Cash paid for interest	$	89,~~616~~937		$	1629,~~155~~988
Non-cash financing and investing activities:
Lease assets obtained in exchange for lease liabilities	$	~~110~~182		$	—
Asset retirement obligations, net	$	~~229~~251		$	~~136~~12,294
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	$	544,~~512~~782		$	97,~~144~~502
Restricted cash at end of period	34,~~750~~449			6,~~243~~211
Cash and cash equivalents and restricted cash at end of period	$	949,~~262~~231		$	1513,~~387~~713

See accompanying notes to condensed consolidated financial statements

~~VANGUARD~~GRIZZLY ~~NATURAL RESOURCES~~ENERGY, ~~INC.~~LLC AND SUBSIDIARIES

(formerly known as Vanguard Natural Resources, Inc. (Debtor-in-Possession))

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

General

References to the “Company,” refer to Grizzly Energy, LLC and its consolidated subsidiaries as a whole or an individual basis. References to “Vanguard” refer to the Company during the period prior to the Effective Date while references to “Grizzly” refer to the Company during the period following the Effective Date.

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~~maintain ~~shareholder value by growing~~ reserves, production and cash flow in a capital efficient manner while identifying opportunities to return cash to stakeholders. Through our operating subsidiaries, as of ~~March~~June 3130, 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~~were ~~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~~July 19, 2019, ~~we received notice from~~ the ~~OTC~~Bankruptcy ~~Markets~~Court ~~Group~~entered ~~Inc.~~an ~~notifying~~order usconfirming ~~that,~~the ~~effective~~Amended ~~April~~Joint 2,Plan ~~2019,~~of itReorganization ~~was~~(as ~~removing~~Modified) ~~the shares~~ of ~~our~~Vanguard ~~common~~Natural ~~stock~~Resources, ~~par~~Inc. ~~value~~and ~~$0.001~~its Debtor Affiliates (~~“Common~~the ~~Stock~~“Plan”), and ~~two~~on ~~series~~July of16, ~~outstanding~~2019, ~~warrants from~~ the ~~OTCQX~~Company ~~U.S.~~consummated ~~tier of~~ the ~~OTC~~Plan ~~Markets~~ and ~~downgrading~~emerged ~~them~~from to the ~~OTC~~Chapter ~~Pink~~11 inCases. ~~light~~As part of the ~~2019~~transactions ~~Bankruptcy~~undertaken ~~Petitions.~~pursuant ~~The~~to ~~OTC Pink is a more limited market than~~ the ~~OTCQX U.S. tier~~Plan, ~~and~~Vanguard ~~the~~was ~~quotation~~converted offrom ~~our~~a ~~Common~~Delaware ~~Stock~~corporation onto ~~the OTC Pink may result in~~ a ~~less~~Delaware ~~liquid~~limited ~~market~~liability ~~available~~company ~~for existing~~ and ~~potential~~renamed ~~stockholders~~Grizzly toEnergy, ~~trade~~LLC ~~our Common Stock and could further depress the trading price of our Common Stock~~(“Grizzly”). ~~There~~See ~~can~~Note be2 ~~no assurance that any public market~~ for ~~our~~a ~~Common~~discussion ~~Stock~~of ~~will exist in~~ the ~~future~~Chapter or11 ~~that the Company or its successor will be able to participate again in the OTCQX U~~proceedings.~~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.

1. Summary ~~Going~~of ~~Concern~~Significant ~~Assessment~~Accounting Policies

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~~June 3130, 2019, our significant accounting policies, except for those related to the effects of our Chapter 11 Cases discussed below, 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~~June 3130, 2019 and December 31, 2018, and for the three and six months ended ~~March~~June 3130, 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~~are bepotentially impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.


(b)	Oil and Natural Gas Properties

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

Depreciation, depletion and amortization

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

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~~Vanguard ~~Company~~was is a C corporation subject to federal and state income taxes. Grizzly has elected to be treated as a C corporation for 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~~June 3130, 2019, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.


(d)	New Pronouncements Recently Adopted

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

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

The adoption of ASU 2016-02 resulted in the recording of additional net lease assets and lease liabilities of approximately $17.5 million and $18.0 million, respectively, as of January 1, 2019, with the difference largely due to prepaid and deferred rent that were reclassified to the right-of-use (“ROU”) asset value. The standard did not require any adjustment to the opening balance of retained earnings and had no impact on cash flows. Please see Note 9, “Leases,” for further details.

In June 2016, the FASB issued ASU 2016-13 - Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which provides financial statement users with more decision-useful information about

~~The~~the ~~adoption~~expected ofcredit ~~ASU~~losses ~~2016-02~~on ~~resulted~~financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To comply with this, the amendments in this Update replace the ~~recording~~incurred ofloss ~~additional~~impairment ~~net~~methodology ~~lease~~in ~~assets~~current GAAP with a methodology that reflects expected credit losses and ~~lease~~requires ~~liabilities~~consideration of ~~approximately~~a ~~$17.5~~broader ~~million~~range of reasonable and ~~$18~~supportable information to inform credit loss estimates.0 ~~million~~The measurement of expected credit losses will be based on relevant information about past events, ~~respectively~~including historical experience, ascurrent conditions, and reasonable and supportable forecasts that affect the collectibility of ~~January~~the 1reported amount. In May 2019, the FASB updated Topic 326 by issuing ASU 2019-05, ~~with~~Financial ~~the~~Instruments-Credit ~~difference~~Losses ~~largely~~(Topic ~~due~~326): toTargeted ~~prepaid~~Transition ~~and~~Relief, ~~deferred~~which ~~rent~~provides entities that ~~were~~have ~~reclassified~~certain toinstruments within the ~~right-~~scope of Subtopic 326-~~use~~20, ~~(“ROU”)~~Financial ~~asset~~Instruments-Credit ~~value.~~Losses ~~The~~- ~~standard~~Measured ~~did~~at ~~not~~Amortized ~~require~~Cost, ~~any~~with ~~adjustment~~an option to irrevocably elect the ~~opening~~fair ~~balance~~value ofoption ~~retained~~in ~~earnings~~Subtopic ~~and~~825-10, ~~had~~Financial noInstruments-Overall, ~~impact~~applied on ~~cash~~an ~~flows~~instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. ~~Please~~The ~~see~~amendments ~~Note~~in 10these Updates will be applied using a modified-retrospective approach and, ~~“Leases~~for public entities,” are effective for ~~further~~fiscal ~~details~~years beginning after December 15, 2019 and interim periods within those annual periods. Management does not expect this update to have a material impact on the Company's financial statements.

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~~share-~~cash~~based compensation. Actual results could differ from those estimates.

~~(f)~~2. Chapter ~~Prior~~11 ~~Year Financial Statement Presentation~~Proceedings

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~~the ~~31,~~Petition ~~2019~~Date, the ~~2019~~ Debtors filed the ~~2019~~ Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court. The ~~2019~~ Debtors ~~are~~were ~~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~~were ~~VNG~~GNG, ~~VNRH~~GEH, VOGO, EOC, EAC, ~~ERAC~~GAC, ~~ERUD~~GUD, ~~ERAP~~GAP, ~~ERAC~~GAC II, ~~ERUD~~GUD II and ~~ERAP~~GAP II.

Reorganization Process

WeThroughout ~~are~~the ~~currently~~Chapter ~~operating~~11 Cases, we operated 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~~continued 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~~authorized us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions ~~are~~were 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, subject to certain exceptions, 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~~prohibited, for example, our lenders, or noteholders and other creditors 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~~were ~~(subject to certain exceptions) be~~ settled or compromised under the Bankruptcy Code through the ~~2019~~ Chapter 11 Cases.

10Our operations and ability to execute our business remain subject to the risks and uncertainties arising as a result of our Chapter 11 Cases, and the number and nature of our outstanding common units and unitholders, assets, liabilities, officers and managers could change materially because of our Chapter 11 Cases. In addition, the descriptions of our prepetition operations, properties and capital plans may not accurately reflect our post-emergence operations, properties and capital plans.

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~~10

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~~consisted 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 iswas 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~~were be subject to further amendment or modification after filing. Many of the claims identified in the Schedules and Statements ~~are~~were listed as disputed, contingent or unliquidated.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who ~~wish~~wished to assert prepetition claims against us and whose claim (i) iswere not listed in the Schedules and Statements or (ii) iswere listed in the Schedules and Statements as disputed, contingent, or unliquidated, ~~must~~were required to file a proof of claim with the Bankruptcy Court prior to the bar ~~date~~dates 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~~August 1014, 2019, approximately 831,405 claims totaling $27.37 ~~million~~billion ~~have~~were ~~been~~ filed with the Bankruptcy Court against the ~~2019~~ Debtors by approximately 731,206 claimants. We expect additional claims to be filed prior to the last bar ~~dates~~date. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We anticipate the claims filed against the ~~2019~~ Debtors in the ~~2019~~ Chapter 11 Cases will be numerous. We expect the process of resolving claims filed against the ~~2019~~ Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with the ~~2019~~ Plan. As part of the process, we will work to resolve differences in amounts scheduled by the ~~2019~~ Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where necessary. Accordingly, the ultimate number and amount of claims that will be allowed against the Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated. As discussed above, the claims resolution process continues following our emergence from the Chapter 11 Cases.

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 (“VNG”), 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~~VNG 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~~VNG Credit Facility (the “Term Loan Claims”). On July 3, 2019, the Plan Support Agreement was amended to reflect the support of over 66 2/3% of Second Lien Notes. A summary of the restructuring transactions agreed to by the Plan Support Parties and effectuated through the Plan is included below.

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

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

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

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

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

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

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

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

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

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

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

Debtor-in-Possession Financing

In connection with the ~~2019~~ Chapter 11 Cases, on the ~~2019~~ Petition Date, the ~~2019~~ Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the ~~2019~~ Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG, as borrower (the “DIP Borrower”), Citibank, N.A., as administrative agent and issuing bank (the “DIP Agent”), and 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 iswas Citibank N.A. The DIP Credit Agreement ~~contains~~contained 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 and an additional $5.0 million was drawn in July 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”);11

• ~~proceeds~~a of“roll ~~the~~up” ~~New~~of ~~Money~~$65.0 ~~Facility~~million ~~may~~of ~~be used by~~ the ~~DIP~~outstanding ~~Borrower~~principal toamount ~~(i)~~of ~~pay~~the ~~certain~~revolving ~~costs~~loans ~~and~~under ~~expenses related to~~ the ~~2019~~VNG ~~Chapter~~Credit 11Facility ~~Cases,~~ (~~ii)~~as ~~make~~defined ~~payments~~in ~~provided~~Note ~~for~~5) in (the ~~DIP Motion, including in respect of certain~~ “~~adequate protection~~Roll-Up”, ~~obligations~~ and ~~(iii) fund working capital needs~~, ~~capital~~together ~~improvements~~with ~~and other general corporate purposes of~~ the ~~DIP~~New ~~Borrower~~Money ~~and~~Facility, ~~its subsidiaries~~collectively, ~~in all cases subject to~~ the ~~terms of the~~ “DIP ~~Credit Agreement and applicable orders of the Bankruptcy Court~~Facility”);

• ~~the~~proceeds ~~maturity date~~ of the ~~DIP~~New ~~Credit~~Money ~~Agreement~~Facility iswere ~~expected~~ to be ~~the~~used ~~earliest~~by tothe ~~occur~~DIP ofBorrower to (ai) ~~nine~~pay ~~months~~certain ~~after~~costs and expenses related to the ~~2019~~Chapter ~~Petition~~11 ~~Date~~Cases, (bii) make payments provided for in the ~~consummation~~DIP ofMotion, aincluding ~~sale~~in respect of ~~all~~certain or“adequate ~~substantially~~protection” ~~all~~obligations ofand ~~the~~(iii) ~~equity~~fund working capital needs, capital improvements and~~/or~~ ~~assets~~other general corporate purposes of the DIP Borrower and its subsidiaries, ~~(c)~~in ~~the~~all ~~occurrence~~cases ~~of an event of default (~~subject to ~~any~~the ~~cure~~terms ~~periods),~~of ~~and (d)~~ the ~~effective~~DIP ~~date~~Credit ofAgreement aand ~~plan~~applicable orders of ~~reorganization in~~ the ~~2019~~Bankruptcy ~~Chapter 11 Cases.~~Court;

• ~~interest~~the ~~will~~DIP ~~accrue~~Credit atAgreement awas ~~rate~~paid ~~per~~off ~~year~~prior ~~equal~~ to ~~the~~maturity ~~LIBOR~~on ~~rate~~July ~~plus 5.50%~~16, or2019 ~~the~~in ~~adjusted~~connection ~~base~~with ~~rate~~Grizzly’s ~~plus~~emergence ~~4.50%~~from ~~per~~the ~~annum~~Chapter 11 Cases;

• ininterest ~~addition~~accrued toat ~~fees~~a torate beper ~~paid~~year toequal ~~the DIP Agent, the DIP Borrower is required~~ to ~~pay to~~ the ~~DIP~~LIBOR ~~Agent~~rate ~~for~~plus ~~the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1~~5.050% ~~of the daily average of each lender’s unused commitment under the New Money Facility~~, ~~which~~or ~~is payable in arrears on~~ the ~~last~~adjusted ~~day~~base ofrate ~~each~~plus ~~calendar~~4.50% ~~month~~per ~~and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid~~annum; and

• ~~the~~in ~~obligations~~addition ~~and~~to ~~liabilities~~other offees ~~the~~paid ~~DIP Borrower and its subsidiaries owed~~ to the DIP Agent, ~~and lenders under~~ the DIP ~~Credit~~Borrower ~~Agreement~~was ~~and~~required ~~related~~to ~~loan~~pay ~~documents will be entitled~~ to ~~joint~~the ~~and~~DIP ~~several~~Agent ~~super-priority~~for ~~administrative~~the ~~expense~~account ~~claims against each~~ of the ~~DIP~~lenders ~~Borrower~~under ~~and its subsidiaries in their respective 2019 Chapter 11 Cases subject to limited exceptions provided for in~~ the DIP ~~Motion,~~Credit ~~and will be secured by (i) a first priority~~Agreement, ~~priming~~an ~~security~~unused ~~interest~~commitment ~~and~~fee ~~lien~~equal onto ~~all~~1.0% ~~encumbered property~~ of the ~~DIP~~daily ~~Borrower~~average ~~and~~of ~~its~~each ~~subsidiaries,~~lender’s ~~subject~~unused tocommitment ~~limited~~under ~~exceptions provided for in~~ the ~~DIP~~New ~~Motion~~Money Facility, ~~(ii)~~which awas ~~first~~payable ~~priority~~in ~~security~~arrears ~~interest and lien~~ on ~~all~~the ~~unencumbered~~last ~~property~~day of ~~the~~each ~~DIP~~calendar ~~Borrower~~month and ~~its~~on ~~subsidiaries,~~the ~~subject~~termination todate ~~limited exceptions provided~~ for in the ~~DIP~~facility ~~Motion~~for ~~and~~any ~~(iii)~~period afor ~~junior~~which ~~security~~the ~~interest~~unused ~~and~~commitment ~~lien~~fee onwas ~~all~~not ~~property~~previously ofpaid.

Plan of Reorganization

On July 9, 2019, the Bankruptcy Court entered an order confirming the Amended Joint Plan of Reorganization (as Modified) of Vanguard Natural Resources, Inc. and its Debtor Affiliates (the “Plan”) and on July 16, 2019, the Company consummated the Plan. The Plan provides for the reorganization of the Debtors as a going concern and will significantly reduce long-term debt and annual interest payments of the reorganized Debtors.

The following is a summary of the material terms of the Plan. This summary highlights only certain substantive provisions of the Plan and is not intended to be a complete description of the Plan. The Plan provided for:


•	holders of an allowed claim related to the DIP Credit Agreement to receive their pro rata share of participation in the Revolving Loans/Term Loan A (each as defined below);


•	holders of allowed RBL Claims and allowed Secured Swap Claims to receive their pro rata share of and interest in: (i) the Term Loan B (as defined below); (ii) the Series A Preferred Units (the “Series A Preferred Units”); and (iii) 75% of the Series C Common Units (the “Series C Common Units”);

•

holders of allowed claims under the senior secured term loan credit facility pursuant to the VNG Credit Facility to receive a pro rata share and interest in 10% of the Series C Common Units, 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 Series A Preferred Units; or (ii) such holder’s pro rata share of the Series B Preferred Units (the “Series B Preferred Units” and together with the Series A Preferred Units, the “Preferred Units”);


•	holders of allowed claims related to the VNG Notes to receive a pro rata share and interest in: (i) 15% of the Series C Common Units, if the class of Allowed Senior Note Claims voted to accept the Plan; (ii) the Series A Preferred Units; and (iii) cash;


•	holders of certain other allowed general unsecured claim to receive 2% of the face amount of its unpaid claim as further described in the Plan; and


•	customary releases, exculpations, and injunctions.

Pursuant to the Plan, the terms of the Vanguard’s board of directors expired as of the Effective Date. Our current board of managers (the “Board”) consists of five members who, except for one manager, are different from those who previously served on Vanguard’s board of directors.

Preferred and Common Units

The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us, at our option, in accordance with the terms of the Company’s limited liability company agreement (the “LLC Agreement”). The Preferred Units had an initial liquidation preference of $10.00 per unit (the “Initial Liquidation Preference”).

From and after the date on which the Term Loan B is repaid, the Company may redeem, in whole or in part, the Series A Preferred Units, at such times as determined by the Board in its sole discretion at the price set forth in the LLC Agreement (the “Series A Redemption Price”). The Series A Redemption Price, at a given date of determination, is based upon an amount equal to the Initial Liquidation Preference increased each month by an annualized rate equal to the LIBO rate for such month, plus 9.5%, compounding monthly on the last day of each such month. Upon the redemption of any Series A Preferred Units and the payment in full to the holders thereof, such Series A Preferred Units will cease to be outstanding.

From and after the date on which all Series A Preferred Units are redeemed by Grizzly and are no longer outstanding (the “Series A Redemption Date”), the Company may redeem, in whole or in part, the Series B Preferred Units, at such times as determined by the Board in its sole discretion at the price set forth in the LLC Agreement (the “Series B Redemption Price”). The Series B Redemption Price, at a given date of determination, is based upon an amount equal to the Initial Liquidation Preference increased each month by an annualized rate equal to the LIBO rate for such month, plus 10.5%, compounding monthly on the last day of each such month. Upon the redemption of any Series B Preferred Units and the payment in full to the holders thereof, such Series B Preferred Units will cease to be outstanding.

The Common Units represent limited liability company interests. Record holders of Common and Preferred Units are entitled to vote at meetings of members and shall be entitled to one vote for each outstanding unit that is registered in the name of such member on the record date for such meeting.

Exit Facility

Grizzly has entered into that certain Fifth Amended and Restated Credit Agreement dated as of July 16, 2019 (the “RBL Credit Agreement”), among GNG, as borrower (the “RBL Borrower”), Grizzly, as parent, Citibank, N.A., as administrative agent, issuing bank and collateral agent, and the lenders party thereto from time to time. Pursuant to the RBL Credit Agreement, the lenders party thereto agreed to provide a new first-lien reserved-based credit facility with first-out revolving credit commitments in the aggregate amount of $65.0 million (the “Revolving Loans”) and a second-out term loan in the aggregate amount of $65.0 million (the “Term Loan A”). The initial borrowing base under the RBL Credit Agreement is $65.0 million. The borrowing base will be redetermined semi-annually on April 1st and October 1st of each year, commencing on April 1, 2020.

The maturity date of the RBL Credit Agreement, including the Term Loan A, is July 16, 2022. Until the maturity date, the Term Loan A shall bear interest at a rate per annum equal to 3.0% plus the adjusted LIBO rate for an alternate base rate loan, or 4.0% plus the adjusted LIBO rate for a Eurodollar loan, and the Revolving Loans shall bear interest based on borrowing base utilization percentage at a rate per annum equal to the alternate base rate plus a margin ranging from 2.0% to 3.0% for alternative base rate loans or the adjusted LIBO rate plus a margin ranging from 3.0% to 4.0% for Eurodollar loans. Unused commitments under the RBL Credit Agreement will accrue a commitment fee at a rate of 0.5%, payable quarterly in arrears.

The RBL Borrower will be required to repay the Term Loan A at the end of each quarter in equal quarterly installments at a rate of 1.0% per annum of the original principal amount of the Term Loan A.

Grizzly has also entered into that certain Term Loan Credit Agreement dated as of July 16, 2019 (the “Term Loan Credit Agreement”) among GNG, as borrower (the “Term Loan Borrower”), Grizzly, as parent, Citibank, N.A., as administrative agent and collateral agent, and the lenders party thereto from time to time. Pursuant to the Term Loan Credit Agreement, the lenders party thereto agreed to provide a first-lien, last-out term loan in the aggregate amount of $285.0 million (the “Term Loan B”). The Term Loan Credit Agreement and the RBL Credit Agreement together are referred to herein as the “Exit Facility”.

The maturity date of the Term Loan Credit Agreement is January 16, 2023. Until the maturity date, the Term Loan B shall bear interest at a rate per annum equal to (i) the alternate base rate plus an applicable margin of 6.5% for an alternate base rate loan or (ii) the adjusted LIBO rate plus an applicable margin of 7.5% for a Eurodollar loan.

The obligations under the ~~DIP~~Exit ~~Borrower~~Facility are guaranteed by Grizzly and ~~its~~all of Grizzly’s subsidiaries ~~that~~(the is“Guarantors”), subject to ~~(a)~~limited ~~a valid~~exceptions, ~~perfected~~ and ~~non~~secured on a first-~~avoidable~~priority ~~lien~~basis asby substantially all of Grizzly’s and the ~~petition~~Guarantors’ ~~date~~assets, ~~(other~~including, ~~than~~without ~~the~~limitation, ~~first~~liens ~~priority~~on ~~and~~at ~~second~~least ~~priority~~95% ~~prepetition~~of ~~liens)~~the ortotal ~~(b)~~value aof ~~valid~~Grizzly’s and ~~non-avoidable~~the ~~lien~~Guarantors’ ~~that~~oil isand ~~perfected~~natural ~~subsequent~~gas toproperties, ~~the~~and ~~petition~~pledges ~~date,~~of inequity ~~each~~interests ~~case~~of ~~subject~~all toother ~~limited~~direct ~~exceptions~~and ~~provided~~indirect ~~for~~subsidiaries inof ~~the~~Grizzly, ~~DIP~~subject ~~Motion;~~to certain limited exceptions.

•The ~~the~~Exit ~~DIP~~Facility also contains certain financial covenants. The RBL Credit Agreement isrequires ~~subject~~that toas ~~customary~~of ~~covenants,~~the ~~including~~last aday ~~requirement~~of ~~that~~any fiscal quarter commencing with the ~~Company~~third ~~maintain~~full afiscal ~~minimum~~quarter ~~liquidity~~ending ~~(as~~after ~~defined~~the ineffective date of the ~~DIP~~RBL Credit Agreement, that (i) ofthe ~~$10~~consolidated first-out leverage ratio not exceed 2.050 ~~million,~~to ~~prepayment~~1.00 ~~events,~~and ~~events~~(ii) current ratio not be less than 1.00 to 1.00. The Term Loan Credit Agreement requires that as of ~~default~~January ~~and~~1 ~~other~~of ~~provisions;~~each year and July 1 of each year, commencing with the first such date after the effective date of the Term Loan Credit Agreement, that the proved developed producing coverage ratio not be less than 1.00 to 1.00.

•Amended ~~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~~Restated ~~Roll-Up~~Employment ~~is contemplated to be converted into an exit term loan as of such date.~~Agreements

~~The~~Richard ~~relief~~Scott ~~requested~~Sloan inAmended ~~the~~and ~~DIP~~Restated ~~Motion~~Employment ~~was approved by the Bankruptcy Court on April 30, 2019.~~Agreement

On July 16, 2019, Grizzly entered into an Amended and Restated Employment Agreement with its President and Chief Executive Officer, Richard Scott Sloan (the “Sloan Employment Agreement”). The initial term of the Sloan Employment Agreement will begin on July 16, 2019, and end on December 31, 2020, which term shall automatically renew for one-year periods unless Grizzly or Mr. Sloan gives notice that it or he, as applicable, does not wish to extend the agreement. The employment agreement provides that Mr. Sloan is entitled to receive an annual base salary of $720,000 and an annual target bonus equal to 100% of his base salary; provided that during the 2019 calendar year, Mr. Sloan will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $180,000 (the “Sloan STIP”). The Sloan STIP permits Mr. Sloan to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Sloan can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the Sloan Employment Agreement are generally consistent with the terms of Mr. Sloan’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Sloan’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Ryan Midgett Amended and Restated Employment Agreement

On July 16, 2019, Grizzly entered into an Amended and Restated Employment Agreement with its Chief Financial Officer, Ryan Midgett (the “Midgett Employment Agreement”). The initial term of the Midgett Employment Agreement will begin on July 16, 2019, and end on December 31, 2020, which term shall automatically renew for one-year periods unless Grizzly or Mr. Midgett gives notice that it or he, as applicable, does not wish to extend the agreement. The Midgett Employment Agreement provides that Mr. Midgett is entitled to receive an annual base salary of $325,000 and an annual target bonus equal to 80% of his base salary; provided that during the 2019 calendar year, Mr. Midgett will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $65,000 (the “Midgett STIP”). The Midgett STIP permits Mr. Midgett to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Midgett can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the agreement are generally consistent with the terms of Mr. Midgett’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Midgett’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Jonathan C. Curth Amended and Restated Employment Agreement

On July 16, 2019, Grizzly entered into an Amended and Restated Employment Agreement with its General Counsel, Corporate Secretary and Vice President of Land, Jonathan C. Curth (the “Curth Employment Agreement”). The initial term of the Curth Employment Agreement will begin on July 16, 2019, and end on December 31, 2020, which term shall automatically renew for one-year periods unless the Company or Mr. Curth gives notice that it or he, as applicable, does not wish to extend the agreement. The Curth Employment Agreement provides that Mr. Curth is entitled to receive an annual base salary of $380,000 and an annual target bonus equal to 80% of his base salary; provided that during the 2019 calendar year, Mr. Curth will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $76,000 (the “Curth STIP”). The Curth STIP permits Mr. Curth to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Curth can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the agreement are generally consistent with the terms of Mr. Curth’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Curth’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Emergence from Chapter 11

On the Effective Date, the Debtors substantially consummated the Plan and emerged from the Chapter 11 Cases. As part of the transactions undertaken pursuant to the Plan, Vanguard was converted to a Delaware limited liability company and renamed Grizzly Energy, LLC.

Acceleration of Debt Obligations

As of December 31, 2018, the Company was not in compliance with certain covenants under the ~~Successor~~VNG Credit Facility (as defined in Note 65). Accordingly, all amounts due under the ~~Successor~~VNG Credit Facility and ~~New~~VNG Notes (as defined in Note 65) (collectively, the “Debt Instruments”) ~~are~~were 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.

•The ~~$677.7~~commencement ~~million~~of ~~in unpaid principal with respect to~~ the ~~Revolving~~Chapter ~~Loan~~11 ~~(defined~~Cases inwas ~~Note~~an ~~6),~~event ~~$123.4~~of ~~million~~default inthat ~~unpaid~~accelerated ~~principal with respect to~~ the ~~Term~~Debtors’ ~~Loan~~obligations ~~(defined in Note 6), and approximately $11.6 million of interest, fees, and other expenses arising~~ under ~~or in connection with~~ the ~~Successor~~following ~~Credit~~Debt ~~Facility.~~Instruments:

• $80677.7 million in unpaid principal with respect to the VNG Revolving Loan (defined in Note 5), ~~plus~~$123.4 million in unpaid principal with respect to the Term Loan (defined in Note 5), and approximately $11.6 million of interest, fees, and other expenses, arising under or in connection with the ~~New~~VNG ~~Notes~~Credit ~~issued~~Facility; ~~pursuant to the Amended~~ and ~~Restated Indenture.~~

~~Any~~• ~~efforts~~$80.7 tomillion ~~enforce~~in ~~such~~unpaid ~~obligations~~principal, ~~under~~plus ~~the~~interest, ~~Debt~~fees, ~~Instruments are stayed automatically as a result of the filing of the 2019 Bankruptcy Petitions~~ and ~~the~~other ~~holders’~~expenses, ~~rights~~arising ~~of enforcement~~ in ~~respect~~connection ofwith the ~~Debt~~VNG ~~Instruments~~Notes ~~are~~issued ~~subject~~pursuant to the ~~applicable~~Amended ~~provisions~~and ofRestated ~~the Bankruptcy Code~~Indenture.

As of June 30, 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 did not accrue interest on the Debt Instruments during the pendency of the 2019 Chapter 11 Cases.

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~~had the right to assume, assign or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. IfRejections weof ~~reject~~contracts ~~a contract~~ or ~~lease~~leases, ~~such rejection~~ generally (1) iswere treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, ~~relieves~~relieved the ~~2019~~ Debtors of performing their future obligations under such contract or lease and (3) ~~entitles~~entitled the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. IfAssumption weof ~~assume an~~ executory ~~contract~~contracts or unexpired ~~lease~~leases, ~~we are~~ generally required the Company 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:~~15

14future performance to the counterparty. Accordingly, any description of an executory contract or unexpired lease, including any quantification of our obligations under any such contract or lease, is wholly qualified by the rejection rights we had under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto.

	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

The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of June 30, 2019:



	June 30, 2019
	(in thousands)
Accounts payable	$	3,233
Accrued liabilities	308
Undistributed oil and gas revenues	13,782
Derivative liabilities	53,870
Other liabilities	5
Debt and accrued interest	894,407
Liabilities subject to compromise	$	965,605

Interest Expense

We discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $15.7 million, representing contractual interest expense from the Petition Date through June 30, 2019.

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 the three and six months ended ~~March~~June 3130, 2019 and 2018:

	Three Months Ended March 31, 2019
	Three Months Ended				Six Months Ended
	(in thousands)
	June 30,				June 30,
Professional and legal fees (1)	$	12,077
	2019		2018		2019		2018
Deferred financing costs and debt discount (2)	6,311
Professional and legal fees (1)	$	24,743	$	610	$	36,820	$	2,317
Total Reorganization items	$	18,388
Deferred financing costs and debt discount (2)	—		—		6,311		—
Total Reorganization items	$	24,743	$	610	$	43,131	$	2,317

(1) ~~All~~Includes $14.1 million of accrued reorganization costs as of June 30, 2019 representing unpaid professional and legal fees ~~were~~directly ~~incurred~~related to the Chapter 11 Cases. Total payments made for professional and ~~paid~~legal asfees ofrelated ~~March~~to 31the Chapter 11 Cases amounted to $22.7 million for the six months ended June 30, 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 VNG Revolving Loan, Term Loan and ~~New~~VNG Notes as these debt instruments ~~are~~were expected to be impacted by the bankruptcy reorganization process.

~~4. Revenues~~Going Concern

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 adjustments as a result of this substantial doubt.

3. Revenues

Revenue from Contracts with Customers

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

Natural gas and NGLs Sales

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

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

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~~six months ended ~~March~~June 3130, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

54. 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~~VNG Credit Facility (defined in Note 65, “Debt”).

165. Debt

6. Debt

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

Description	Interest Rate	Maturity Date	~~March~~June 3130, 2019			December 31, 2018
Revolving Loan	Variable (1)	February 1, 2021	$	677,718		$	682,145
VNG 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
New Money Facility	Variable (3)		20,000			—
Lease Financing Obligations	4.16%	August 10, 2020 (3)	—			10,454
VNG Notes	9.0%	February 15, 2024	80,722			80,722
Lease Financing Obligations	4.16%	August 10, 2020 (4)	—			10,454
Unamortized deferred financing costs			—			(7,124		)
Total debt			$	~~881~~901,878		$	889,635
Less:
Liabilities subject to compromise (Note 3)			(881,878		)	—
Liabilities subject to compromise (Note 2)			(881,878		)	—
Long-term debt classified as current (4)			—			(879,181		)
Short-term debt			(20,000		)	—
Current portion of Lease Financing Obligation (3)			—			(5,008		)
Long-term debt classified as current (5)			—			(879,181		)
Current portion of Lease Financing Obligation (4)			—			(5,008		)
Total long-term debt			$	—		$	5,446

(1) Variable interest rate of 6.~~53% and 6.~~27% at ~~March~~December 31, ~~2019~~2018. ~~and~~In ~~December~~accordance 31with ASC 852, ~~2018~~Reorganizations, ~~respectively~~we have accrued interest expense only up to the Petition Date.

(2) Variable interest rate of ~~10.28% and~~ 9.96% at ~~March~~December 31, ~~2019~~2018. ~~and~~In ~~December~~accordance 31with ASC 852, ~~2018~~Reorganizations, ~~respectively~~we have accrued interest expense only up to the Petition Date.

(3) ~~Under~~Variable ~~ASU~~interest ~~No.~~rate ~~2016-02,~~of ~~the~~7.92% ~~lease~~at ~~financing~~June ~~obligations~~30, ~~are~~2019. ~~classified~~Borrowings ~~and presented~~ under the ~~“Lease~~New ~~Assets”~~Money ~~line~~Facility ~~item~~were inpaid ~~the~~off ~~Balance~~prior ~~Sheet.~~to ~~See~~maturity ~~Note~~on ~~10,~~July ~~“Leases~~16,” ~~for~~2019 ain ~~detailed~~connection ~~discussion~~with ofGrizzly’s ~~our~~emergence ~~leases~~from the Chapter 11 Cases.

(4) Under ~~ASC~~ASU ~~Topic~~No. ~~470~~2016-02, ~~“Debt,”,~~the aslease afinancing ~~result~~obligations ofare ~~our~~classified ~~debt~~and ~~covenant~~presented ~~violations,~~under wethe ~~classified~~“Lease ~~our~~Liabilities” ~~debt~~line ~~under~~item ~~our~~in ~~Revolving~~the ~~Loan,~~Balance ~~Term~~Sheet. ~~Loan~~See ~~and~~Note ~~New~~9, ~~Notes~~“Leases,” asfor ~~current~~a atdetailed ~~December~~discussion ~~31,~~of ~~2018~~our leases.


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

Acceleration of Debt Obligations

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

Successor Credit Facility

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

; and

As of December 31, 2018, the Company was not in compliance with certain covenants under the VNG Credit Facility (iidefined herein). ~~a ratio~~Accordingly, ~~determined~~all amounts due under the Debt Instruments are classified as ofcurrent in the ~~last~~accompanying ~~day~~consolidated balance sheets as of ~~each~~that ~~fiscal~~date. ~~quarter~~The ~~for~~commencement of the ~~four~~Chapter ~~fiscal-quarter~~11 ~~period~~Cases ~~then~~is ~~ending,~~an ~~commencing~~event ~~with~~of default that accelerated the ~~fiscal~~Debtors’ ~~quarter~~obligations ~~ending~~under ~~December~~these 31Debt Instruments. As of June 30, ~~2017~~2019, ofamounts ~~current~~outstanding ~~assets~~under tothe ~~current~~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 ~~VNR~~the filing of the Bankruptcy Petitions and ~~its~~the ~~subsidiaries~~holders’ onrights aof ~~consolidated~~enforcement ~~basis~~in respect of ~~not~~the ~~less~~Debt ~~than~~Instruments ~~1.00~~are subject to 1the applicable provisions of the Bankruptcy Code.~~00.~~

~~The~~We ~~calculation~~accelerated the amortization of ~~EBITDA~~the remaining debt issue costs of $6.3 million associated with the Debt Instruments, fully amortizing those amounts as ~~defined~~of ~~under~~the Petition Date. Since the ~~Second~~commencement ~~Amendment,~~of ~~among~~the ~~other~~Bankruptcy ~~things~~Petitions, ~~include~~no ~~addbacks~~interest inhas ~~respect~~been paid to the holders of ~~certain~~the ~~exploration~~Debt ~~expenses~~Instruments. Also, asin ~~well~~accordance aswith ~~third~~ASC ~~party~~852, ~~fees~~Reorganizations, ~~costs~~we ~~and~~have ~~expenses~~accrued ininterest ~~connection~~expense ~~with~~on the ~~Plan~~Debt Instruments only up to the Petition Date. The total amount accrued of ~~Reorganization,~~$12.5 ~~also~~million ~~defined~~is inreflected as liabilities subject to compromise on the ~~Second~~consolidated ~~Amendment,~~balance ~~together~~sheet ~~with~~as ~~related~~of ~~severance~~June 30, ~~costs~~2019. In addition, contractual interest on liabilities subject to ~~certain~~compromise ~~limitations~~not reflected in the consolidated statements of operations was approximately $15.7 million, representing interest expense from the Petition Date through June 30, 2019.

~~The~~Additional ~~Successor~~information ~~Credit~~regarding ~~Facility~~the ~~also~~Chapter ~~contains~~11 ~~certain~~cases ~~events~~is ofincluded ~~default,~~in ~~including,~~Note ~~without~~2. ~~limitation:~~Chapter ~~non-payment;~~11 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 bankruptcyCases.

~~New~~VNG ~~Notes~~Credit Facility

OnUnder ~~August~~the 1,Company’s ~~2017~~Fourth Amended and Restated Credit Agreement (the “VNG Credit Facility”), the ~~Company~~lenders ~~issued~~party ~~approximately~~thereto ~~$80.7~~agreed ~~million~~to ~~aggregate~~provide ~~principal~~VNG ~~amount~~with ofan 9$850.0% ~~Senior~~million ~~Secured~~senior ~~Second~~secured ~~Lien~~reserve-based ~~Notes~~revolving ~~due~~credit ~~2024~~facility (the “~~New~~VNG ~~Notes~~Revolving Loan”). toThe ~~certain~~VNG ~~eligible~~Credit ~~holders~~Facility ofalso ~~the~~included ~~Predecessor’s~~an ~~second~~additional ~~lien~~$125.0 ~~notes~~million senior secured term loan (the “~~Existing~~Term ~~Notes~~Loan”). inAs ~~satisfaction~~ of ~~their~~June 30, ~~claim~~2019, ofthe ~~approximately~~VNG Credit Facility had a borrowing base of $80677.79 million. ~~related~~Pursuant to the ~~Existing~~Plan, ~~Notes~~on ~~held~~the byEffective ~~such~~Date, ~~holders.~~the Company’s obligations with respect to the VNG Credit Facility were canceled and discharged.

~~The~~VNG ~~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~~On ~~New~~June ~~Notes are governed by an Amended and Restated Indenture~~30, ~~dated as of August 1~~2019, ~~2017~~we ~~(as~~had ~~amended,~~$80.7 ~~the~~million ~~“Amended~~outstanding ~~and~~in ~~Restated~~aggregate ~~Indenture”),~~principal byamount ~~and~~of ~~among~~9.0% ~~the~~Senior ~~Company,~~Secured ~~certain~~Second ~~subsidiary~~Lien ~~guarantors~~Notes ofdue ~~the~~2024 ~~Company~~ (the “~~Guarantors~~VNG Notes”). ~~and~~Pursuant ~~Delaware~~to ~~Trust~~the ~~Company~~Plan, ason ~~Trustee~~the ~~(in~~Effective ~~such capacity~~Date, the ~~“Trustee”)~~Company’s ~~and~~obligations aswith ~~Collateral~~respect ~~Trustee~~to ~~(in such capacity,~~ the ~~“Collateral~~VNG ~~Trustee”),~~Notes ~~which~~were ~~contains~~canceled ~~customary affirmative~~ and ~~negative covenants~~discharged.

~~The~~Exit 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. Facility

~~Interest~~Grizzly ishas ~~payable~~entered oninto the ~~Senior~~RBL ~~Notes~~Credit ~~due~~Agreement. ~~2024~~Pursuant onto ~~February~~the 15RBL Credit Agreement, the lenders party thereto agreed to provide the Revolving Loans and ~~August~~the 15Term Loan A. The initial borrowing base on the Revolving Loans is $65.0 million. The maturity date of ~~each~~the ~~year~~RBL Credit Agreement is July 16, ~~which~~2022. ~~began~~The onCompany ~~February~~has 15also entered into that certain Term Loan Credit Agreement. Pursuant to the Term Loan Credit Agreement, ~~2018~~the lenders party thereto agreed to provide a first-lien, last-out term loan in the aggregate amount of $285.0 million. The ~~Senior~~maturity ~~Notes~~date ~~due~~of ~~2024~~the ~~will~~Term ~~mature~~Loan onCredit ~~February~~Agreement 15is January 16, ~~2024~~2023. See Note 2 for a detailed discussion of the Exit Facility.

At6. ~~any~~Price ~~time~~Risk ~~prior~~Management toActivities 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.

OnHistorically, orwe ~~after~~entered ~~February~~into ~~15,~~derivative ~~2020~~contracts primarily with counterparties that were also lenders under our VNG Credit Facility to hedge price risk associated with a portion of our oil, ~~the~~natural ~~Senior~~gas ~~Notes~~and ~~due~~NGLs ~~2024~~production. ~~will~~Our bederivative ~~redeemable~~contracts with these counterparties were 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 ~~whole~~early ortermination of such derivative contracts. As a result of our defaults under our debt agreements and our Bankruptcy Petitions, we were in ~~part~~default under our derivative contracts. In addition, atour ~~redemption~~derivative ~~prices~~contract ~~equal~~counterparties were permitted to terminate any outstanding derivative transactions and to calculate the ~~principal~~amounts ~~amount~~due ~~multiplied~~to byor from the ~~percentage~~Debtors ~~set~~as ~~forth~~a ~~below~~result of such terminations, ~~plus~~in ~~accrued~~accordance ~~and~~with ~~unpaid~~the ~~interest,~~terms ifof ~~any~~the agreements governing such derivative contracts. In April 2019, our derivative contract counterparties unilaterally terminated all derivative contracts to ~~the~~which ~~redemption~~we ~~date,~~were ifa ~~redeemed~~party ~~during~~and the ~~twelve-month~~net ~~period~~settlement ~~beginning~~owed to counterparties amounted to $53.9 million and was included in Liabilities Subject to Compromise on ~~February~~the 15Consolidated Balance Sheet as of ~~the~~June ~~years~~30, ~~indicated~~2019. ~~below:~~The Company has not entered into any commodity derivative contracts subsequent to June 30, 2019.

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

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

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	Weighted AverageFixed Price		Bbls	Weighted AverageWTI Price		Gallons	Weighted AverageFixed 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

	Oil
Contract Period	Bbls	Weighted Avg. BasisDifferential ($/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~~period indicated (in thousands):

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

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



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

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

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. As previously discussed, all of our counterparties were participants in our ~~Successor~~VNG Credit Facility (see Note 65, “Debt” for further discussion), which is secured by our oil and natural gas properties; therefore, we were not required to post any collateral. ~~The~~As ~~maximum amount~~ of ~~loss~~June ~~due~~30, to2019, ~~credit risk that~~ we ~~would~~had ~~incur~~no ifoutstanding ~~our~~commodity ~~counterparties~~price ~~failed~~or ~~completely~~interest torate ~~perform~~derivative ~~according to the terms of the~~ contracts, ~~based~~and ontherefore ~~the~~no ~~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
	Six Months Ended June 30, 2019			Year Ended December 31, 2018
Derivative asset (liability) at beginning of period, net	$	6,570		$	(64,437	)
Purchases
Net losses on commodity derivative contracts	(70,202		)	(9,259		)
Net losses on commodity and interest rate derivative contracts	(61,139		)	(9,259		)
Cash settlements paid on matured commodity derivative contracts	9,762			80,266
Settlements
Termination of commodity derivative contracts	53,870			—
Cash settlements paid on matured commodity derivative contracts	16,089			80,266
Derivative asset at end of period, net	$	—		$	6,570
Derivative asset (liability) at end of period, net	$	(38,480	)	$	6,570

87. Fair Value Measurements

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

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



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

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

The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the ~~three~~six months ended ~~March~~June 3130, 2019, we incurred impairment charges of $0323.46 million as oil and natural gas properties with a net cost basis of $1546.12 million were written down to their fair value of $0222.76 million. The most significant factors causing us to record an impairment of oil and natural gas properties in 2019 was the reduction in our proved reserves and the reduction in the value of our unproved properties resulting from a decline in forward natural gas prices. During the ~~three~~six months ended ~~March~~June 3130, 2018, we incurred impairment charges of $1422.62 million as oil and natural gas properties with a net cost basis of $7389.01 million were written down to their fair value of $5866.49 million. The write downs in 2018 primarily relate to downward revisions of unproved property leasehold acreage and working interest in certain of our undeveloped leasehold ~~and~~as awell as the 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.

98. 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



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	4,377
Liabilities related to assets divested	(294		)
Retirements	(1,563		)
Change in estimate	(22		)
Asset retirement obligation at June 30, 2019	145,771
Less: current obligations	(4,752		)
Long-term asset retirement obligation at June 30, 2019	$	141,019

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~~six months ended ~~March~~June 3130, 2019, ~~our~~we used credit-adjusted risk-free interest rate ~~was~~ranging from 6.3% to 6.8% and the average inflation factor was 1.6%.

109. Leases

We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets ~~and~~, asother ~~result~~current ~~of the 2019 Chapter 11 Cases, the lease~~ liabilities ~~are~~and ~~included~~other inlong-term 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 and six months ended ~~March~~June 3130, 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:



		Three Months Ended		Six Months Ended
Lease Expense	Classification	June 30, 2019		June 30, 2019
Assets
Short-term lease cost	Selling, general and administrative expenses or Lease operating expenses	$	371	$	666
Operating lease cost	Selling, general and administrative expenses or Lease operating expenses	670		1,521

Finance lease cost
Amortization of lease assets	Depreciation, depletion, amortization and accretion	1,341		2,674
Interest on lease liabilities	Interest expense	125		262
Net lease cost		$	2,507	$	5,123

	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	%

Information regarding our lease terms and discount rates as of June 30, 2019 were as follows:



	June 30, 2019
Weighted-average remaining lease term (years)
Operating leases	5.8
Finance leases	1.6
Weighted-average discount rate
Operating leases	18.5	%
Finance leases	5.7	%

Supplemental balance sheet information related to leases as of ~~March~~June 3130, 2019 was as follows:

Leases (in thousands)	Classification	~~March~~June 3130, 2019
Assets
Operating lease assets	Lease assets	$	65,~~272~~699
Finance lease assets, at cost	Lease assets	10,~~564~~636
Accumulated amortization	Lease assets	(12,~~333~~674		)
Finance lease assets, net	Lease assets	97,~~231~~962
Total lease assets		$	1513,~~503~~661
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,~~466~~116
Finance	Liabilities subject to compromise	5,~~099~~183
Long-Term
Operating	Liabilities subject to compromise	5,~~255~~051
Finance	Liabilities subject to compromise	42,~~234~~969
Total lease liabilities		$	1614,~~054~~319

The maturity of our lease liabilities as of ~~March~~June 3130, 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):



	Operating Leases			Finance Leases			Total
2019 (remaining of year)	$	1,221		$	2,755		$	3,976
2020	1,763			4,427			6,190
2021	1,557			1,347			2,904
2022	1,255			55			1,310
2023	1,247			—			1,247
Thereafter	3,150			—			3,150
Total undiscounted lease liability	10,193			8,584			18,777
Imputed interest	(4,026		)	(432		)	(4,458		)
Total discounted liability	$	6,167		$	8,152		$	14,319

	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

Supplemental cash flow and other information related to leases for the six months ended June 30, 2019 was as follows (in thousands):

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.



	Six Months Ended
	June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,870
Operating cash flows from finance leases	$	262
Financing cash flows from finance leases	$	2,484

11Rent expense for our office leases was $0. ~~Commitments~~6 million and ~~Contingencies~~$1.1 million for the three and six months ended June 30, 2018, respectively. 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.

10. Commitments and Contingencies

Lease Commitments

25As of December 31, 2018, the minimum contractual obligations under our lease commitments were approximately $9.2 million in the aggregate. Please see Note 9, “Leases,” for a detailed discussion of our current accounting for leases with the adoption of ASU 2016-02.

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~~June 3130, 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~~June 3130, 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



	June 30, 2019
	(in thousands)
July 1, 2019 - December 31, 2019	$	410
2020	410
Total	$	820

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~~June 3130, 2019, total estimated costs to be spent in 2019 is approximately $129.06 million, of which $52.05 million relates to our drilling and completion commitments in the Pinedale field in the Green River Basin, and $6.1 million is for facility redevelopment costs for the Cotton Valley gas plant in Gulf Coast.

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, with certain exceptions, our legal proceedings ~~are~~were automatically stayed, ~~subject~~as to ~~reinstatement~~the ~~when~~Debtors ~~either~~through the Effective Date. Please see Note 2, “Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases.

~~Chapter~~ 11 ~~Cases are terminated or the automatic stay is lifted~~. Stockholders’ ~~Please~~Equity ~~see Note 3, “2019 Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases.~~(Deficit)

~~12. Stockholders’~~Effect ~~Equity~~of Filing on Shareholders

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition debt liabilities and post-petition liabilities must be satisfied in full before the holders of our common shares and warrants are entitled to receive any distribution or retain any property under a plan of reorganization.

Pursuant to the Plan the common shares and warrants of Vanguard were cancelled and Grizzly and its affiliates do not have any obligations thereunder.

Earnings Per Share

Basic earnings per share is computed by dividing net earnings attributable to stockholders by the weighted average number of shares outstanding during the period. Diluted earnings per share is computed by adjusting the average number of shares 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 six months ended June 30, 2019 and 2018 excluded 301,065 restricted stock units (“RSUs”) and 143,181 RSUs, respectively, and approximately 1.3 million warrants for each of the period, that were antidilutive.

12. Share-Based Compensation

Effect of Emergence from Bankruptcy on Share-Based Compensation

Pursuant to the Plan, all unvested equity grants outstanding immediately before the Effective Date were canceled and of no further force or effect as of the Effective Date. In addition, on the Effective Date, the Company’s 2017 Management Incentive Plan (“MIP”) was canceled and extinguished, and participants in the 2017 MIP received no payment or other distribution on account of the 2017 MIP.

2017 MIP Restricted Stock Units

The following table summarizes our time-based RSUs as of June 30, 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 June 30, 2019	243,023		$	16.65

As of June 30, 2019, the total remaining unearned compensation related to non-vested time-based RSUs was $2.7 million with a weighted-average remaining service period of 1.5 years.

In addition, the total remaining unearned compensation related to TSR performance RSUs as of June 30, 2019 was $0.8 million, with a weighted-average remaining service period of 1.5 years.

Pursuant to the Plan, all RSUs issued by Vanguard were cancelled and Grizzly and its affiliates do not have any obligations related thereto.

Our condensed consolidated statements of operations reflect non-cash compensation related to our MIP of $0.6 million for each of the three months ended June 30, 2019 and 2018, and $1.2 million and $1.1 million for the six months ended June 30, 2019 and 2018, respectively.

13. Income Taxes

For the six months ended June 30, 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. As described in Note 2, “Chapter 11 Proceedings,” in accordance with the Plan, our long-term debt was reorganized and significantly reduced. The Internal Revenue Code (“IRC”) of 1986, as amended, provides that a debtor in a Chapter 11 bankruptcy case may exclude cancellation of debt income (“CODI”) from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. Upon emergence from Chapter 11 bankruptcy proceedings, the CODI may reduce some or all of the amount of prior U.S. tax attributes. The actual reduction in tax attributes will not occur until after the determination of tax for the 2019 taxable year. The utilization of certain remaining U.S. tax attributes are expected to be limited under IRC Section 382 due to the ownership change resulting from the Plan. Based on historical results and ownership change limitations, during the six months ended June 30, 2019, the Company recorded 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.

Upon emergence, the Company has elected to be treated as a C corporation for federal and state income taxes.

~~Warrant~~14. ~~Agreement~~Related Parties

OnOne ~~August~~of ~~1, 2017,~~ the ~~Company~~members ~~entered~~of ~~into a warrant agreement (~~the ~~“Warrant Agreement”) with American Stock Transfer & Trust~~ Company,’s ~~LLC~~Board, asKevin ~~warrant agent~~Asarnow, ~~pursuant~~is toalso ~~which~~an ~~the~~Executive ~~Company~~Director ~~issued:~~at ~~(i)~~RPA ~~to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”)~~Advisors, ~~(B)~~LLC ~~7.625% Series B Cumulative Redeemable Perpetual Preferred Units~~ (“~~Series B Preferred Units~~RPA”)~~, and (C) 7~~.~~75%~~ ~~Series~~RPA Cserved ~~Cumulative~~as ~~Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with~~ the ~~Series~~financial Aadvisor ~~Preferred~~to ~~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~~allowed ~~Predecessor’s~~RBL ~~common~~Claims ~~units representing limited liability company interests, three~~ and aallowed ~~half~~Secured ~~year~~Swap ~~warrants~~Claims ~~(the~~during ~~“Common Unit Warrants” and, together with~~ the ~~Preferred~~Chapter ~~Unit~~11 ~~Warrants,~~Cases. ~~the~~The ~~“Warrants”)~~Company ~~which~~incurred ~~are~~professional ~~exercisable~~fees torelated ~~purchase up~~ to ~~640,876~~services ~~shares~~provided ofby ~~Common~~RPA ~~Stock. The expiration date~~ of ~~the~~approximately ~~Warrants is February 1, 2021~~$2.2 ~~The~~million ~~strike price~~ for the ~~Preferred~~six ~~Unit~~months ~~New~~ended ~~Warrants~~June is30, ~~$44~~2019.~~25,~~ ~~and~~We ~~the~~accrued ~~strike~~professional ~~price~~services ~~for~~expense ~~the~~of ~~Common Unit New Warrants is~~ $610.~~45.~~5 Asmillion ~~set~~for ~~forth~~services ~~above,~~rendered ~~the~~but ~~2019 Plan does~~ not ~~contemplate~~yet ~~providing~~paid aas ~~recovery to any holders~~ of ~~current~~June ~~equity~~30, ~~including the Warrants~~2019.

~~Earnings~~Until ~~Per~~August ~~Share/Unit~~2018, Dean E. Swick, also a member of the Company’s Board and Audit Committee Chairman, was a Managing Director at Alvarez & Marsal North America, LLC (“A&M”) where he served as the Co-Leader of Energy Restructuring. Another Alvarez & Marsal entity (the “A&M entity”) provided services to the Company related to the analysis of executive compensation. The Company incurred professional fees related to services provided by the A&M entity of approximately $0.2 million for the six months ended June 30, 2019. There were no outstanding amounts owed to the A&M entity as of June 30, 2019.

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 AverageGrant Date Fair Value
Non-vested at December 31, 2018	244,496		$	16.62
Vested	(1,473	)	$	11.99
Non-vested at March 31, 2019	243,023		$	16.65

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

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

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

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

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

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

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.

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 and six months ended ~~March~~June 3130, 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


•	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~~June 3130, 2019, based on internal reserve estimates, our total estimated proved reserves were ~~1,015~~955.81 Bcfe, of which approximately 64% were natural gas reserves, 2019% were oil reserves and 1617% 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~~June 3130, 2019, we owned working interests in 10,~~226~~424 gross (3,~~576~~674 net) productive wells. Our operated wells accounted for approximately 6059% of our total estimated proved reserves at ~~March~~June 3130, 2019. Our average net daily production for the ~~three~~six months ended ~~March~~June 3130, 2019 and the year ended December 31, 2018 was ~~297~~296 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 accordance with the terms of the agreements governing such derivative contracts. In April 2019, our derivative contract counterparties

2928

~~accordance~~unilaterally ~~with~~terminated ~~the~~all ~~terms of the agreements governing such~~ derivative contracts. Into ~~April~~which ~~2019,~~we ~~our~~were ~~derivative~~a ~~contract~~party. ~~counterparties~~We ~~unilaterally~~currently ~~terminated~~have ~~all~~no commodity derivative contracts toin ~~which we were a party~~place.

Bankruptcy Proceedings under Chapter 11

~~2019~~Commencement ~~Chapter~~of 11Bankruptcy ~~Proceedings~~Cases

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~~were ~~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 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 ~~Successor~~guarantors party thereto, Citibank N.A., as Administrative Agent, and the other lenders party thereto from time to time (as amended, the “VNG 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 VNG Credit Facility (the “Term Loan Claims”). On July 3, 2019, the Plan Support Agreement was amended to reflect the support of over 66 2/3% of Second Lien Notes. A summary of the restructuring transactions agreed to by the Plan Support Parties and effectuated through the Plan is included below. Capitalized terms used but not defined in this Quarterly Report are defined in the Plan Support Agreement and the Plan.

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 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 GNG, as borrower (the “DIP Borrower”), Citibank, N.A., as administrative agent and issuing bank (the “DIP Agent”), and the financial institutions or other entities from time to time parties thereto, as lenders, and the DIP Agent ~~and as issuing bank~~. The initial lender under the DIP Credit Agreement iswas Citibank N.A. The DIP Credit Agreement contained the following terms:

~~The~~• ~~relief~~a ~~requested~~super-priority senior secured revolving credit facility in the ~~DIP~~aggregate ~~Motion~~amount ~~was~~of ~~approved~~up byto $65.0 million (the ~~Bankruptcy~~“New ~~Court~~Money Facility”), of which $20.0 million was drawn on April 304, 2019 and an additional $5.0 million was drawn in July 2019;

~~Automatic~~• ~~Stay~~a “roll up” of $65.0 million of the outstanding principal amount of the revolving loans under the VNG Credit Facility (as defined in Note 5 to the condensed consolidated financial statements) (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);

~~Subject~~• proceeds of the New Money Facility were to be used by the DIP Borrower to (i) pay certain ~~specific~~costs ~~exceptions~~and ~~under~~expenses related to the ~~Bankruptcy~~Chapter ~~Code~~11 Cases, (ii) make payments provided for in the ~~2019~~DIP ~~Bankruptcy~~Motion, ~~Petitions~~including ~~automatically~~in ~~stayed~~respect ~~most~~of ~~judicial~~certain or“adequate ~~administrative~~protection” ~~actions~~obligations ~~against~~and (iii) fund working capital needs, capital improvements and other general corporate purposes of the ~~Company~~DIP Borrower and ~~efforts~~its bysubsidiaries, ~~creditors~~in all cases subject to ~~collect~~the onterms orof ~~otherwise~~the ~~exercise~~DIP ~~rights~~Credit orAgreement ~~remedies~~and ~~with~~applicable ~~respect~~orders toof ~~pre-petition~~the ~~claims.~~Bankruptcy Court;


•	the DIP Credit Agreement was paid off prior to maturity on July 16, 2019 in connection with Grizzly’s emergence from the Chapter 11 Cases;


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


•	in addition to other fees paid to the DIP Agent, the DIP Borrower was required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.00% of the daily average of each lender’s unused commitment under the New Money Facility, which was 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 was not previously paid.

Plan of Reorganization


•	holders of an allowed claim related to the DIP Credit Agreement to receive their pro rata share of participation in the Revolving Loans/Term Loan A (each as defined below);


•	holders of allowed RBL Claims and allowed Secured Swap Claims to receive their pro rata share of and interest in: (i) the Term Loan B (as defined below); (ii) the Series A Preferred Units; and (iii) 75% of the Series C Common Units;

•

holders of allowed claims under the senior secured term loan credit facility pursuant to the VNG Credit Facility to receive a pro rata share and interest in 10% of the Series C Preferred Units, 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 Series A Preferred Units; or (ii) such holder’s pro rata share of the Series B Preferred Units;


•	holders of allowed claims related to the VNG Notes to receive a pro rata share and interest in: (i) 15% of the Series C Common Units, if the class of Allowed Senior Note Claims voted to accept the Plan; (ii) the Series A Preferred Units; and (iii) cash;


•	holders of certain other allowed general unsecured claim to receive 2% of the face amount of its unpaid claim as further described in the Plan; and


•	customary releases, exculpations, and injunctions.

Exit Facility

Grizzly has entered into that certain Fifth Amended and Restated Credit Agreement dated as of July 16, 2019 (the “RBL Credit Agreement”), among GNG, as borrower (the “RBL Borrower”), Grizzly, as parent, Citibank, N.A., as administrative agent, issuing bank and collateral agent, and the lenders party thereto from time to time. Pursuant to the RBL Credit Agreement, the lenders party thereto agreed to provide a new first-lien reserved-based credit facility with first-out revolving credit commitments in the aggregate amount of $65.0 million (the “Revolving Loans”) and a second-out term loan in the aggregate amount of $65.0 million (the “Term Loan A”). The initial borrowing base under the Revolving Loans is $65.0 million. The borrowing base will be redetermined semi-annually on April 1st and October 1st of each year, commencing on April 1, 2020.

The maturity date of the RBL Credit Agreement is July 16, 2022. Until the maturity date, the Term Loan A shall bear interest at a rate per annum equal to 3.0% for an alternate base rate loan or 4.0% for a Eurodollar loan, and the Revolving Loans shall bear interest based on borrowing base utilization percentage at a rate per annum equal to 2.0% to 3.0% for alternative base rate loans or 3.0% to 4.0% for Eurodollar loans. Unused commitments under the RBL Credit Agreement will accrue a commitment fee at a rate of 0.5%, payable quarterly in arrears.

The RBL Borrower will be required to repay the Term Loan A at the end of each quarter in equal quarterly installments at a rate of 1.0% per annum of the original principal amount of the Term Loan A.

(the “Term Loan B”). The Term Loan Credit Agreement and the RBL Credit Agreement together are referred to herein as the “Exit Facility”.

The maturity date of the Term Loan Credit Agreement is January 16, 2023. Until the maturity date, the Term Loan B shall bear interest at a rate per annum equal to 6.50% for an alternate base rate loan or 7.5% for a Eurodollar loan.

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

The Exit Facility also contains certain financial covenants. The RBL Credit Agreement requires that as of the last day of any fiscal quarter commencing with the third full fiscal quarter ending after the effective date of the RBL Credit Agreement, that (i) the consolidated first-out leverage ratio not exceed 2.50 to 1.00 and (ii) current ratio not be less than 1.00 to 1.00. The Term Loan Credit Agreement requires that as of January 1 of each year and July 1 of each year, commencing with the first such date after the effective date of the Term Loan Credit Agreement, that the proved developed producing coverage ratio not be less than 1.00 to 1.00.

Amended and Restated Employment Agreements

Richard Scott Sloan Amended and Restated Employment Agreement

On July 16, 2019, Grizzly entered into an Amended and Restated Employment Agreement with its President and Chief Executive Officer, Richard Scott Sloan (the “Sloan Employment Agreement”). The initial term of the Sloan Employment Agreement will begin on July 16, 2019, and end on December 31, 2020, which term shall automatically renew for one-year periods unless Grizzly or Mr. Sloan gives notice that it or he, as applicable, does not wish to extend the agreement. The Sloan Employment Agreement provides that Mr. Sloan is entitled to receive an annual base salary of $720,000 and an annual target bonus equal to 100% of his base salary; provided that during the 2019 calendar year, Mr. Sloan will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $180,000 (the “Sloan STIP”). The Sloan STIP permits Mr. Sloan to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Sloan can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the Sloan Employment Agreement are generally consistent with the terms of Mr. Sloan’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Sloan’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Ryan Midgett Amended and Restated Employment Agreement

On July 16, 2019, Grizzly entered into an Amended and Restated Employment Agreement with its Chief Financial Officer, Ryan Midgett (the “Midgett Employment Agreement”). The initial term of the Midgett Employment Agreement will begin on July 16, 2019, and end on December 31, 2020, which term shall automatically renew for one-year periods unless Grizzly or Mr. Midgett gives notice that it or he, as applicable, does not wish to extend the agreement. The Midgett Employment Agreement provides that Mr. Midgett is entitled to receive an annual base salary of $325,000 and an annual target bonus equal to 80% of his base salary; provided that during the 2019 calendar year, Mr. Midgett will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $65,000 (the “Midgett STIP”). The Midgett STIP permits Mr. Midgett to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Midgett can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the Midgett Employment Agreement are generally consistent with the terms of Mr. Midgett’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Midgett’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Jonathan C. Curth Amended and Restated Employment Agreement

the agreement. The Curth Employment Agreement provides that Mr. Curth is entitled to receive an annual base salary of $380,000 and an annual target bonus equal to 80% of his base salary; provided that during the 2019 calendar year, Mr. Curth will instead participate in a quarterly bonus arrangement that provides him the opportunity to earn a target quarterly bonus of $76,000 (the “Curth STIP”). The Curth STIP permits Mr. Curth to earn a quarterly bonus if performance metrics are achieved during the applicable calendar quarter on either a stand-alone or “catch up” basis. Mr. Curth can earn up to 150% of his quarterly target bonus if the applicable performance metrics are exceeded. The other terms of the Curth Employment Agreement are generally consistent with the terms of Mr. Curth’s prior agreement, except that: (i) the Effective Date of the Plan shall constitute a Change of Control (as defined therein), and (ii) Mr. Curth’s voluntary resignation during the 30-day period following the three-month anniversary of the Effective Date of the Plan shall constitute Good Reason (as defined herein).

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the ~~2019~~Company ~~Debtors~~and ~~may~~the Chapter 11 Subsidiaries had the right to assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. ~~The~~Rejection ~~rejection~~ of an executory contract or unexpired lease iswas generally treated as a ~~pre-petition~~prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the ~~2019~~Company ~~Debtors~~and the Chapter 11 Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may ~~give~~have given rise to a ~~pre-petition~~prepetition 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 debt 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~~as continued, does not ~~contemplate~~provide ~~providing~~ any economic recovery to holders of our existing common stock. ~~The~~Please ~~ultimate~~read ~~recovery~~Note 2, “Chapter 11 Proceedings” of the Notes to ~~creditors,~~the ifCondensed Consolidated Financial Statements for further discussion on plan provisions.

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~~Emergence ~~Associated~~from ~~with 2019~~ Chapter 11 ~~Cases~~

~~For~~On the ~~duration~~Effective ~~of our 2019 Chapter 11 Cases~~Date, ~~our~~the ~~operations~~Debtors ~~and~~substantially ~~our~~consummated ~~ability to develop and execute our business plan are subject to~~ the ~~risks~~Plan and ~~uncertainties~~emerged ~~associated~~from ~~with~~ the Chapter 11 ~~process~~Cases. asAs ~~described~~part inof ~~Part~~the Itransactions -undertaken ~~Item~~pursuant ~~1A,~~to ~~Risk~~the ~~Factors in our 2018 Annual Report and in Part II - Item 1A~~Plan, ~~Risk~~Vanguard ~~Factors~~was inconverted ~~this~~to ~~Quarterly~~a ~~Report.~~Delaware ~~Because~~limited ofliability ~~these~~company ~~risks~~ and ~~uncertainties,~~renamed ~~the~~Grizzly ~~description of our operations~~Energy, ~~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~~LLC.

Later this year, the Company intends to list on the OTC, our Series C Common Units, our Series A Preferred Units, and our Series B Preferred Units.

Capital Development

Total capital expenditures were approximately $1121.05 million during the ~~three~~six months ended ~~March~~June 3130, 2019. ~~Subject~~While towe ~~the~~have ~~satisfaction~~sufficient ofaccess ~~the~~to ~~conditions under the Final Dip Order and DIP Credit Agreement~~capital, we are currently ~~anticipate~~undertaking a ~~total~~review of our capital expenditures ~~budget~~opportunities ~~ranging~~in ~~from~~conjunction ~~$43.0~~with ~~million~~other opportunities to ~~$50.0~~improve ~~million~~stakeholder value for the ~~full~~balance ~~year~~ of 2019. Weand ~~have~~beyond. ~~reduced~~However, ~~our~~we ~~capital~~anticipate ~~expenditures~~that ~~budget~~we ~~for~~are ~~2019~~committed ~~primarily due~~ to ~~less~~spend ~~drilling~~approximately ~~activity in the Pinedale Basin~~$5.0 ~~During~~million ~~the~~on ~~three~~operated ~~months~~capital ~~ended~~projects ~~March~~and ~~31,~~approximately ~~2019, we participated in the drilling of 41 gross (6~~$10.42 ~~net)~~million on non-operated ~~wells~~capital ~~and~~projects inover the ~~completion~~balance of ~~16 gross (1~~2019.3 ~~net) non-operated wells.~~

InDuring the ~~Arkoma~~six ~~Basin~~months weended ~~expect~~June ~~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~~30, 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~~participated in the drilling of ~~vertical~~58 ~~natural~~gross ~~gas wells with partners Ultra Petroleum Corporation and Pinedale Energy Partners~~(10. In6 ~~addition~~net) tonon-operated ~~our~~wells ~~drilling~~ and ~~completion~~in ~~programs, we expect to spend approximately $6.0 million to $8.0 million for~~ the ~~remainder~~completion of ~~2019~~31 ongross ~~other~~(4.3 ~~uplift~~net) ~~projects, primarily in the Permian New Mexico Red Lake field, as we continue our successful 2018~~ non-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~~.

3132

Results of Operations

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

	Three Months Ended						Six Months Ended
	March 31,
	June 30,						June 30,
	2019 (a)			2018
	2019			2018			2019			2018
Revenues:
Oil sales	$	3237,~~748~~150		$	46,~~111~~503		$	69,897		$	92,614
Natural gas sales	6229,~~314~~132			5542,~~267~~623			91,446			97,890
NGLs sales	1413,~~048~~702			2122,~~897~~587			27,749			44,484
Oil, natural gas and NGLs sales	~~109~~79,~~110~~984			~~123~~111,~~275~~713			189,092			234,988
Net losses on commodity derivative contracts	(619,~~139~~063		)	(1845,~~585~~332		)	(70,202		)	(63,917		)
Total revenues and losses on commodity derivative contracts	$	4770,~~971~~921		$	~~104~~66,~~690~~381		$	118,890		$	171,071
Costs and expenses:
Production:
Lease operating expenses	2629,~~247~~035			3036,~~995~~763			55,282			67,758
Transportation, gathering, processing and compression	98,~~522~~484			119,~~502~~768			18,006			21,270
Production and other taxes	97,~~823~~833			97,~~781~~971			17,656			17,752
Depreciation, depletion, amortization, and accretion	3539,~~714~~044			4038,~~039~~711			74,758			78,750
Impairment of oil and natural gas properties	~~438~~323,188			147,~~601~~552			323,626			22,153
Exploration expense	~~201~~275			~~1,316~~430			476			1,746
Selling, general and administrative expenses	118,~~966~~648			1210,~~240~~529			20,614			22,769
Non-cash compensation	591			496
Share-based compensation	590			579			1,181			1,075
Total costs and expenses	$	94417,~~502~~097		$	~~120~~112,~~970~~303		$	511,599		$	233,273
Other income (expense):
Interest expense	$	(16,975	)	$	(14,753	)
Interest expense (excludes contractual interest expense of $15.7 million for each of the three and six months ended June 30, 2019)	$	(1,680	)	$	(15,870	)	$	(18,655	)	$	(30,623	)
Net losses on divestitures of oil and natural gas properties	(458		)	—
Net gain (loss) on divestitures of oil and natural gas properties	—			4,900			(458		)	4,900
Other	87497			~~149~~(175		)	586			(26		)
Reorganization items	(1824,~~388~~743		)	(~~1,707~~610		)	(43,131		)	(2,317		)

~~(a)~~Three ~~During~~Months ~~the~~Ended ~~three~~June ~~months ended March 31~~30, 2019, weCompared ~~divested~~to ~~certain~~Three ~~oil~~Months ~~and~~Ended ~~natural~~June ~~gas properties and related assets. As such~~30, ~~there~~2018 ~~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~~80.10 million and $~~123~~111.37 million for the three months ended ~~March~~June 3130, 2019 and 2018, respectively. The key oil, natural gas and NGLs revenue measurements were as follows:

	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

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.



	Three Months Ended
	June 30,
	2019		2018
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	55.13	$	59.32
Natural Gas (Price/Mcf)	$	1.57	$	1.81
NGLs (Price/Bbl)	$	19.37	$	28.45
Average realized prices, including hedges ^(a):
Oil (Price/Bbl)	$	55.13	$	40.65
Natural Gas (Price/Mcf)	$	1.57	$	1.88
NGLs (Price/Bbl)	$	19.37	$	22.18
Average NYMEX prices:
Oil (Price/Bbl)	$	59.83	$	67.89
Natural Gas (Price/Mcf)	$	2.64	$	2.80
Total production volumes:
Oil (MBbls)	674		784
Natural Gas (MMcf)	18,587		23,573
NGLs (MBbls)	707		794
Combined (MMcfe)	26,874		33,041
Average daily production volumes:
Oil (Bbls/day)	7,405		8,615
Natural Gas (Mcf/day)	204,250		259,049
NGLs (Bbls/day)	7,772		8,725
Combined (Mcfe/day)	295,314		363,088


(a)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We have no commodity derivative contracts as of June 30, 2019.

The decrease in total commodity sales during the three months ended June 30, 2019 compared to the same period in 2018 was primarily due to the decrease in our average net daily production for all products resulting from divestitures completed during the second half of 2018 and the first three months of 2019. Our average net daily production was 295,314 Mcfe/day for the three months ended June 30, 2019 and 363,088 Mcfe/day for the three months ended June 30, 2018. Also contributing to the total decrease in total commodity sales was the decrease in the average realized oil, natural gas and NGLs prices, excluding hedges, as a result of lower average NYMEX crude oil price and natural gas price.

Overall, our total production for the three months ended June 30, 2019 decreased by 17% on an Mcfe basis compared to the same period in 2018. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 15%, 69% and 16%, respectively, of our production during the three months ended June 30, 2019 compared to 14%, 71% and 15%, respectively, of our production during the same period in 2018.

Hedging and Price Risk Management Activities

During the three months ended June 30, 2019 and 2018, we recognized a net loss on commodity derivative contracts of $9.1 million and $45.3 million, respectively. The net loss on commodity derivative contracts recorded during the second quarter of 2019 includes the net settlement owed to counterparties as a result of the termination of all our commodity derivative contracts. Our hedging program historically helped 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 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. As of June 30, 2019, we have no commodity derivative contracts in place.

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~~decreased by $267.27 million ~~and~~to $3129.0 million for the three months ended ~~March~~June 3130, 2019 ~~and~~as ~~2018~~compared to the three months ended June 30, ~~respectively~~2018. 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~~June 3130, 2019 decreased as compared to the ~~three~~same ~~months~~period ~~ended~~in ~~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 $98.5 million for the three months ended ~~March~~June 3130, 2019, which represents a decrease from the $119.58 million recorded during the three months ended ~~March~~June 3130, 2018 primarily due to lower natural gas and 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. AsProduction ~~a percentage of wellhead revenues, production~~ and other taxes ~~was~~decreased ~~9.0%~~slightly ~~and~~by 7$0.9%1 million for the three months ended ~~March~~June 3130, 2019 ~~and~~as ~~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~~increased ~~was~~by approximately $350.73 million ~~and~~to $4039.0 million for the three months ended ~~March~~June 3130, 2019 ~~and~~from ~~2018,~~approximately ~~respectively~~$38.7 ~~The~~million ~~decrease~~for inthe ~~depreciation,~~three ~~depletion,~~months ~~amortization,~~ended ~~and~~June ~~accretion~~30, ~~expense~~2018, isprimarily due to a ~~lower~~higher ~~amortization~~depletion ~~base~~rate asresulting afrom ~~result~~lower estimates of ~~the~~oil ~~divestitures completed during 2018~~ and ~~the~~natural ~~three~~gas ~~months ended March 31, 2019~~reserves. 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 $0323.42 million and $147.6 million was recognized during the three months ended ~~March~~June 3130, 2019 and 2018, respectively. The impairment charge recognized during the three months ended ~~March~~June 3130, 2019 was a result of the reduction in our proved reserves resulting from a decline in forward natural gas prices. The write downs in 2018 ~~related~~primarily relate to downward revisions inof ~~our~~ unproved property leasehold acreage and working interest in certain of our undeveloped leasehold as well as the reduction in the value of certain of our operating districts due to a decline in forward natural gas prices.

Exploration expense decreased from $10.34 million during the three months ended ~~March~~June 3130, 2018 to $0.23 million for the three months ended ~~March~~June 3130, 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.

months ended June 30, 2019 and 2018, selling, general and administrative expenses were $8.6 million and $10.5 million, respectively. The decrease is primarily due to lower salaries and wages for the three months ended June 30, 2019 as a result of employee workforce reduction. In addition, we incurred non-cash compensation expense of $0.6 million for each of the three months ended June 30, 2019 and 2018.

Other Income and Expense

Interest expense was $171.07 million and $1415.89 million during the three months ended ~~March~~June 3130, 2019 and 2018, respectively. ~~The~~As ~~increase~~of inthe Petition Date, we discontinued recording interest ~~expense~~on ~~was~~debt ~~primarily~~classified ~~due~~as liabilities subject to ~~higher~~compromise, which resulted in the decrease in interest ~~rates~~expense during 2019.

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 have incurred ~~reorganization~~and will continue to incur significant costs ofassociated ~~$18.4~~with ~~million~~the ~~and~~reorganization ~~$1.7~~in ~~million~~connection ~~for~~with the ~~three~~Chapter ~~months~~11 ~~ended~~Cases. ~~March~~These ~~31,~~costs ~~2019~~are ~~and~~being ~~2018~~expensed as incurred, ~~respectively~~and are expected to significantly affect our results of operations. Reorganization items ~~include~~includes expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, represent professional fees for post-petition expenses. We incurred reorganization costs of $24.7 million for the three months ended June 30, 2019. Reorganization costs of $0.6 million for the three months ended June 30, 2018 were incurred in connection with Vanguard’s Chapter 11 cases filed in 2017.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Revenues

Oil, natural gas and NGLs sales were $189.1 million and $235.0 million for the six months ended June 30, 2019 and 2018 respectively. The key oil, natural gas and NGLs revenue measurements were as follows:



	Six Months Ended
	June 30,
	2019		2018
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	55.43	$	57.24
Natural Gas (Price/Mcf)	$	2.41	$	2.09
NGLs (Price/Bbl)	$	20.41	$	28.18
Average realized prices, including hedges ^(a):
Oil (Price/Bbl)	$	52.19	$	41.17
Natural Gas (Price/Mcf)	$	2.02	$	2.25
NGLs (Price/Bbl)	$	22.59	$	22.48
Average NYMEX prices:
Oil (Price/Bbl)	$	57.78	$	65.31
Natural Gas (Price/Mcf)	$	2.90	$	2.89
Total production volumes:
Oil (MBbls)	1,261		1,618
Natural Gas (MMcf)	37,886		46,944
NGLs (MBbls)	1,360		1,578
Combined (MMcfe)	53,611		66,122
Average daily production volumes:
Oil (Bbls/day)	6,967		8,939
Natural Gas (Mcf/day)	209,316		259,359
NGLs (Bbls/day)	7,512		8,721
Combined (Mcfe/day)	296,191		365,315


(a)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We have no commodity derivative contracts as of June 30, 2019.

The decrease in total commodity sales during the six months ended June 30, 2019 compared to the same period in 2018 was primarily due to the decrease in our average net daily production as a result of divestitures completed during the second half of 2018 and the first six months of 2019. Our average net daily production decreased from approximately 365,315 Mcfe/day for the six months ended June 30, 2018 to 296,191 Mcfe/day for the six months ended June 30, 2019. In addition, the lower sales reflect the decrease in average realized oil price, excluding hedges, due to lower average NYMEX crude oil price. For the six months ended June 30, 2019, our average NYMEX crude oil price reduced by $7.53 per Bbl, or 11.5%, compared to the same period in 2018.

On a Mcfe basis, crude oil, natural gas and NGLs accounted for 14%, 71% and 15%, respectively, of our production during the six months ended June 30, 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 $70.2 million and $63.9 million during the six months ended June 30, 2019 and 2018, respectively. The net loss on commodity derivative contracts recorded during the six months ended June 30, 2019 includes the net settlement owed to counterparties as a result of the termination of all our commodity derivative contracts. Our hedging program historically helped 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 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. As of June 30, 2019, we have no commodity derivative contracts in place.

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 $55.3 million and $67.8 million for the six months ended June 30, 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 during the second half of 2018 and the six months ended June 30, 2019. Overall, spending during the six months ended June 30, 2019 decreased as compared to the six months ended June 30, 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 $18.0 million for the six months ended June 30, 2019, which represents a decrease from the $21.3 million recorded during the six months ended June 30, 2018 primarily due to lower natural gas and 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 9.3% and 7.6% for the six months ended June 30, 2019 and 2018, respectively. The tax rates were higher during six three months of 2019 compared to the same period in 2018 due to lower allowable deductions.

Depreciation, depletion, amortization, and accretion expense was $74.8 million and $78.8 million for the six months ended June 30, 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 six months ended June 30, 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 $323.6 million and $22.2 million was recognized during the six months ended June 30, 2019 and 2018, respectively. The impairment charge recognized during the six months ended June 30, 2019 resulted from the reduction in value of certain of our operating districts due to a decline in forward natural gas prices. The impairment charge for the six months ended June 30, 2018 related to downward revisions in our unproved property leasehold acreage and working interest in certain of our undeveloped leasehold.

Exploration expense decreased from $1.7 million during the six months ended June 30, 2018 to $0.5 million for the six months ended June 30, 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 six months ended June 30, 2019 and 2018, selling, general and administrative expenses were $20.6 million and $22.8 million, respectively. The decrease is primarily due to management severance payments made during the six months ended June 30, 2018. Also, salaries and wages for the six months ended June 30, 2019 were lower due to employee workforce reduction, offset by increased professional fees as a result of management consulting efficiency initiatives. In addition, we incurred non-cash compensation expense of $1.2 million and $1.1 million for the six months ended June 30, 2019 and 2018, respectively.

Other Income and Expense

Interest expense was $18.7 million and $30.6 million during the six months ended June 30, 2019 and 2018, respectively. We discontinued recording interest on our long-term debt classified as liabilities subject to compromise as of the Petition Date resulting in the decrease in interest expense.

During the six months ended June 30, 2019, the Company recorded a net loss of approximately $0.5 million on the sale of oil and natural gas properties.

Reorganization Items

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results of operations. Reorganization items includes expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, represent professional fees for post-petition expenses. In addition, deferred financing costs related to our long-term debt were also included in reorganization items as these debt instruments were impacted by the Chapter 11 Cases. For the six months ended June 30, 2019, we incurred reorganization costs of $43.1 million. For the six months ended June 30, 2018, reorganization costs of $2.3 million were incurred in connection with Vanguard’s Chapter 11 cases filed in 2017.

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.38

~~In addition to the cash requirements necessary to fund ongoing operations~~property, weor ~~have incurred significant professional fees and other costs in connection with our 2019 Chapter 11 Cases and expect that we will continue~~ to ~~incur~~collect ~~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~~monies asowed ofor ~~May~~otherwise ~~10,~~exercise ~~2019~~rights ~~and~~or ~~funds~~remedies ~~generated~~with 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~~a ~~terms~~pre-petition ofclaim ~~the~~are ~~DIP~~enjoined ~~Credit~~unless ~~Agreement~~ and ~~applicable~~until ~~orders of~~ the Bankruptcy Court. ~~The~~lifts ~~DIP Credit Agreement is subject to customary covenants, including a requirement that~~ the ~~Company~~automatic ~~maintain a minimum liquidity (as defined in the DIP Credit Agreement) of $10~~stay.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.

35The 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.

~~However,~~In ~~given~~addition ~~the~~to ~~current level of volatility in~~ the ~~market~~cash ~~and~~requirements ~~the~~necessary ~~unpredictability~~to offund ~~certain~~ongoing ~~costs that could potentially arise in our~~ operations, ~~our~~we ~~liquidity~~have ~~needs~~incurred ~~could~~significant beprofessional ~~significantly~~fees ~~higher than we currently anticipate~~ and ~~therefore~~other ~~the~~costs ~~2019~~in ~~Debtors~~connection ~~filed~~with ~~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~~expect ~~us to emerge from bankruptcy. We can provide no assurance~~ that we ~~will~~may becontinue ~~able~~ to ~~secure~~incur ~~additional~~significant ~~interim~~professional ~~financing~~fees orand ~~exit~~costs ~~financing~~following ~~sufficient to meet~~ our ~~liquidity~~emergence ~~needs~~from ~~or,~~the ifChapter ~~sufficient~~11 ~~funds are available, offered to us on acceptable terms~~Cases.

~~Debtor-in-Possession~~Liquidity ~~Financing~~Following Emergence from the Chapter 11 Cases

~~The~~As ~~DIP~~of ~~Credit~~July ~~Agreement~~16, ~~contains~~2019, Grizzly emerged from the ~~following~~Chapter ~~terms:~~11 Cases with approximately $375.0 million of funded debt and $47.0 million of liquidity comprised of more than $7.0 million in cash and $40.0 million of unused revolver capacity. Please read Note 2, “Chapter 11 Proceedings” of the Notes to the Condensed Consolidated Financial Statements for a detailed discussion of the agreements under our Exit Facility.

• 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

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

	Three Months Ended
	Six Months Ended
	March 31,
	June 30,
	2019			2018
Net cash provided by (used in) operating activities	$	(16,330	)	$	36,249
Net cash provided by operating activities	$	7,859		$	51,108
Net cash used in investing activities	$	(69,~~615~~465	)	$	(4432,~~115~~111	)
Net cash provided by (used in) financing activities	$	(512,~~781~~849	)	$	13(15,~~236~~301	)

Cash Flow from Operations

Net cash ~~used~~provided inby operating activities was approximately $167.39 million for the ~~three~~six months ended ~~March~~June 3130, 2019 compared to ~~net cash provided by operating activities of~~ $3651.21 million for the ~~three~~six months ended ~~March~~June 3130, 2018. Changes in working capital decreased total cash ~~flows~~flow by $2319.54 million for the ~~three~~six months ended ~~March~~June 3130, 2019, and increased total cash ~~flows~~flow by $36.72 million for the ~~three~~six months ended ~~March~~June 3130, 2018. Contributing to the decrease in working capital during the first ~~three~~six months ended 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~~six months of 2018, the increase in working capital resulted from a $1314.91 million decrease in accounts receivable related to the timing of receipts from production, offset by a $96.57 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. WeHistorically, ~~enter~~we have entered into derivative contracts to reduce the impact of commodity price volatility on operations. We have primarily ~~use~~used fixed-price swaps, collars, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. ~~See~~In ~~Note 7~~April of2019, ~~the~~our ~~Notes~~derivative tocontract ~~the~~counterparties ~~Condensed~~unilaterally ~~Consolidated~~terminated ~~Financial~~all ~~Statements,~~derivative ~~included~~contracts ~~under~~to ~~Part~~which I,we ~~Item~~were 1a ofparty. ~~this~~We ~~Quarterly~~currently ~~Report~~have ~~for~~no ~~further~~commodity ~~discussion~~derivative contracts in place.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $69.65 million for the ~~three~~six months ended ~~March~~June 3130, 2019 compared to approximately $4432.1 million for the ~~three~~six months ended ~~March~~June 3130, 2018. Net cash used in investing activities during the first ~~three~~six months ended of 2019 primarily included $46.08 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.39

and $7.1 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 six months of 2018, we spent $42.6 million for drilling and development of oil and natural gas properties and $49.3 million for deposits and prepayments related to the drilling and development of oil and natural gas properties. In addition, we also received net proceeds from the sale of oil and natural gas properties of $59.9 million.

Cash Flow from Financing Activities

Net cash ~~used~~provided inby financing activities was approximately $512.8 million for the ~~three~~six months ended ~~March~~June 3130, 2019 compared to net cash ~~provided~~used byin financing activities of approximately $1315.23 million for the ~~three~~six months ended ~~March~~June 3130, 2018. Net cash ~~used~~provided inby financing activities during the ~~three~~six months ended ~~March~~June 3130, 2019 included proceeds from debtor-in-possession financing of $20.0 million, offset by repayments of debt of $57.81 million. During the ~~three~~six months ended ~~March~~June 3130, 2018, net cash ~~provided~~used byin financing activities primarily included ~~proceeds~~repayments ~~from~~of our revolving credit facility and term loan of $48104.07 million, offset by ~~repayments~~the ofproceeds from our revolving credit facility ~~and term loan~~ of $3490.60 million.

~~Debt~~VNG ~~and~~ Credit ~~Facilities~~Facility and Notes

Acceleration of Debt Obligations

37As of December 31, 2018, the Company was not in compliance with certain covenants under the VNG Credit Facility (defined herein). Accordingly, all amounts due under the Debt Instruments were classified as current in the accompanying consolidated balance sheets as of that date. The commencement of the Chapter 11 Cases is an event of default that accelerated the Debtors’ obligations under these Debt Instruments. As of June 30, 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 Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code.

AsWe ofaccelerated ~~December~~the ~~31,~~amortization ~~2018,~~of the ~~Company~~remaining ~~was~~debt ~~not~~issue incosts ~~compliance~~of ~~with~~$6.3 ~~certain~~million ~~covenants~~associated ~~under~~with the ~~Successor~~Debt ~~Credit~~Instruments, ~~Facility~~fully ~~(defined~~amortizing ~~herein).~~those ~~Accordingly, all~~ amounts ~~due~~as ~~under~~of the ~~Successor~~Petition ~~Credit~~Date. ~~Facility~~Since ~~and~~the ~~New~~commencement ~~Notes~~of ~~(defined~~the ~~herein)~~Bankruptcy ~~(collectively~~Petitions, ~~the~~no ~~“Debt~~interest ~~Instruments”)~~has ~~are~~been ~~classified~~paid asto ~~current in~~ the ~~accompanying~~holders ~~consolidated balance sheet as~~ of ~~that~~the ~~date~~Debt Instruments. ~~The~~Also, ~~commencement~~in ofaccordance ~~the~~with ~~2019~~ASC ~~Chapter~~852, 11Reorganizations, ~~Cases~~we ishave anaccrued ~~event~~interest ofexpense ~~default~~on ~~that accelerated~~ the ~~2019 Debtors’ obligations under these~~ Debt Instruments. Asonly ofup ~~March~~to ~~31,~~the ~~2019,~~Petition ~~amounts~~Date. ~~outstanding~~The ~~under~~total ~~the~~amount ~~Debt~~accrued ~~instruments~~of ~~are~~$12.5 ~~included~~million inis reflected as liabilities subject to compromise inon the ~~condensed~~ consolidated balance sheet. ~~Any efforts to enforce such obligations under the Debt Instruments are stayed automatically~~ as ~~a result~~ of ~~the~~June 30, ~~filing of the~~ 2019. ~~Bankruptcy~~In ~~Petitions~~addition, ~~and~~contractual ~~the~~interest ~~holders’~~on ~~rights~~liabilities ~~of enforcement in respect of the Debt Instruments are~~ subject to ~~the~~compromise ~~applicable~~not ~~provisions~~reflected ofin the ~~Bankruptcy~~consolidated ~~Code.~~statements ~~Further,~~of inoperations ~~accordance~~was ~~with~~approximately ~~accounting~~$15.7 ~~guidance in ASC 852~~million, werepresenting ~~will not accrue~~ interest onexpense ~~the~~from ~~Debt Instruments during~~ the ~~pendency~~Petition ofDate ~~the~~through ~~2019~~June 30, ~~Chapter 11 Cases~~2019.

~~Successor~~VNG Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “~~Successor~~VNG Credit Facility”), the lenders party thereto agreed to provide VNG with an $850.0 million senior secured reserve-based revolving credit facility (the “VNG Revolving Loan”). The ~~Successor~~VNG Credit Facility also ~~includes~~included an additional $125.0 million senior secured term loan (the “Term Loan”). As of ~~March~~June 3130, 2019, the ~~Successor~~VNG Credit Facility had a borrowing base of $677.9 million. Pursuant to the Plan, on the Effective Date, the Company’s obligations with respect to the VNG Credit Facility were canceled and discharged.

AsVNG 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. Notes

~~New~~On June 30, 2019, we had $80.7 million outstanding in aggregate principal amount of 9.0% Senior Secured Second Lien Notes due 2024 (the “VNG Notes”). Pursuant to the Plan, on the Effective Date, the Company’s obligations with respect to the VNG Notes were canceled and discharged.

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. 40

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, which is described in Note 9 of the accompanying condensed consolidated financial statements.

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

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~~Termination ~~loss on divestitures~~ of ~~oil~~commodity ~~and~~derivative ~~natural gas properties~~contracts;

• ~~Compensation~~Net ~~related~~(gain) ~~items,~~loss ~~which~~on ~~include~~divestitures ~~share-based~~of ~~compensation~~oil ~~expense~~and natural gas properties;


•	Share-based compensation expense;


•	Reorganization items;


•	Severance costs;

• ~~Material~~Costs ~~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.

39Adjusted EBITDA attributable to Vanguard stockholders was $26.8 million for the three months ended June 30, 2019 compared to $30.5 million for the three months ended June 30, 2018. Adjusted EBITDA attributable to Vanguard stockholders was $63.1 million for the six months ended June 30, 2019 compared to $82.4 million for the six months ended June 30, 2018. The following table presents a reconciliation of consolidated net loss to Adjusted EBITDA (in thousands):

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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net loss attributable to Vanguard stockholders	$	(372,102	)	$	(57,773	)	$	(454,367	)	$	(90,457	)
Add: Net income attributable to non-controlling interests	—			96			—			189
Net loss	$	(372,102	)	$	(57,677	)	$	(454,367	)	$	(90,268	)
Plus:
Interest expense	1,680			15,870			18,655			30,623
Depreciation, depletion, amortization, and accretion	39,044			38,711			74,758			78,750
Impairment of oil and natural gas properties	323,188			7,552			323,626			22,153
Exploration expense	275			430			476			1,746
Termination of commodity derivative contracts	47,543			—			47,543			—
Change in fair value of commodity derivative contracts^(a)	(38,480		)	27,485			6,570			36,778
Net (gain) loss on divestitures of oil and natural gas properties	—			(4,900		)	458			(4,900		)
Share-based compensation	590			579			1,181			1,075
Reorganization items	24,743			610			43,131			2,317
Severance costs	273			1,845			1,061			4,101
Costs incurred on strategic transactions	—			—			—			148
Adjusted EBITDA before non-controlling interest	26,754			30,505			63,092			82,523
Adjusted EBITDA attributable to non-controlling interest	—			(38		)	—			(75		)
Adjusted EBITDA attributable to Vanguard stockholders	$	26,754		$	30,467		$	63,092		$	82,448

	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						Six Months Ended
	March 31,
	June 30,						June 30,
	2019			2018			2019			2018
Net cash settlements paid on matured commodity derivative contracts	$	~~(16,089~~—	)	$	(917,~~292~~847	)	$	(9,762	)	$	(27,139	)
Change in fair value of commodity derivative contracts	(45,050		)	(9,293		)
Loss on matured commodity derivative contracts not settled	—			—			(6,327		)	—
Net losses on commodity derivative contracts	$	(61,139	)	$	(18,585	)
Change in fair value of commodity derivative contracts	38,480			(27,485		)	(6,570		)	(36,778		)
Termination of derivative contracts	(47,543		)	—			(47,543		)	—
Net losses on commodity derivative contracts	$	(9,063	)	$	(45,332	)	$	(70,202	)	$	(63,917	)

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~~June 3130, 2019 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

~~There~~In ~~were~~April no2019, ~~changes~~we inoutsourced our marketing department to Concord Energy LLC (“Concord”) to perform the Company’s midstream services. In connection with this change, management has implemented certain internal ~~control~~controls over financial reporting ~~that~~to ~~occurred~~ensure ~~during~~we ~~the~~receive ~~first~~accurate ~~quarter~~data offrom ~~2019~~Concord ~~that~~as ~~have~~it ~~materially~~relates ~~affected~~to our revenues, orcommodity ~~are~~pricing ~~reasonably~~and ~~likely~~production tovolumes ~~materially~~as ~~affect,~~well ~~our~~as ~~internal~~the ~~control~~related ~~over~~gathering, ~~financial~~transportation ~~reporting~~and marketing fees.

41There were no other changes in our internal control over financial reporting that occurred during the second quarter of 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Pursuant to 11 U.S.C. § 362, with certain exceptions, our legal proceedings ~~are~~were automatically stayed, ~~subject~~as to ~~reinstatement~~the ~~when~~Debtors ~~either~~through the Effective Date. Please see Note 2, “Chapter 11 Proceedings” of the Notes to the Condensed Consolidated Financial Statements, included under Part I, Item 1 of this Quarterly Report for further discussion regarding our Chapter 11 Cases.

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 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2019, except for the following:

~~The~~We ~~Plan~~recently ~~Support~~emerged ~~Agreement~~from isbankruptcy, ~~subject~~which ~~to significant conditions and milestones that~~ may beadversely ~~difficult~~affect ~~for~~our usbusiness toand ~~satisfy~~relationships.

~~There~~It ~~are~~is ~~certain~~possible ~~material~~that ~~conditions~~our wehaving ~~must~~filed ~~satisfy~~for ~~under~~bankruptcy ~~the~~and ~~Plan~~our ~~Support~~recent ~~Agreement,~~emergence ~~including~~from ~~the~~bankruptcy ~~timely~~may ~~satisfaction~~adversely ofaffect ~~milestones~~our inbusiness ~~the~~and ~~anticipated~~relationships ~~2019~~with ~~Chapter~~customers, ~~11 Cases~~vendors, ~~such~~royalty asor ~~confirmation~~working ofinterest aowners, ~~Chapter 11 plan of reorganization~~contractors, ~~and~~employees ~~effectiveness~~or ~~of such plan~~suppliers. ~~Our~~Due ~~ability~~ to ~~timely~~uncertainties, ~~complete~~many ~~such milestones is subject to~~ risks ~~and~~exist, ~~uncertainties~~including ~~that~~the ~~may be beyond our control.~~following:

If• ~~the~~key ~~Plan~~suppliers, ~~Support~~vendors ~~Agreement~~or isother ~~terminated,~~contract ~~our~~counterparties ~~ability~~may toterminate ~~confirm~~their ~~and~~relationships ~~consummate~~with aus ~~Chapter~~or 11require ~~plan~~additional offinancial ~~reorganization~~assurances ~~could~~or beenhanced ~~materially~~performance ~~and~~from ~~adversely affected.~~us;

~~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~~renew ~~and~~existing ~~consummate~~contracts ~~the~~and ~~2019~~compete ~~Plan.~~for ~~Furthermore,~~new ifbusiness ~~the~~may ~~Plan Support Agreement is terminated, any exit financing upon emergence from the 2019 Chapter 11 Cases will~~ be ~~subject~~adversely ~~to the approval of the Administrative Agent in all respects.~~affected;

~~During~~• ~~the~~our ~~existence~~ability ofto anattract, ~~event~~motivate ~~of default~~ and/or ~~the~~retain ~~2019~~key ~~Chapter~~executives 11and ~~Cases,~~employees wemay ~~have~~be noadversely ~~borrowing capacity under our Successor Credit Facility.~~ affected;

~~Over~~• ~~the~~employees ~~periods~~may ~~presented~~be indistracted ~~the~~from ~~accompanying~~performance ~~financial statements, our growth has been funded through a combination~~ of ~~borrowings~~their ~~under~~duties ~~our~~or ~~Successor~~more ~~Credit~~easily ~~Facility,~~attracted ~~the sale of assets and cash flows from operating activities. We currently have limited access~~ to ~~additional~~other ~~capital.~~employment ~~During~~opportunities; ~~the existence of an event of default, we have no availability under our Successor Credit Facility.~~and

~~The~~• ~~accompanying~~competitors ~~Consolidated~~may ~~Financial~~take ~~Statements~~business ~~have~~away ~~been~~from ~~prepared on a going concern basis that contemplates continuity of operations~~us, ~~realization of assets~~ and ~~liquidation~~our ofability ~~liabilities~~to inattract ~~the~~and ~~ordinary~~retain ~~course~~customers ofmay ~~business. As a result of losses incurred, there is no assurance that the carrying amounts of assets will~~ be ~~realized~~negatively ~~or that liabilities will be settled for the amounts recorded~~impacted. ~~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.~~

42The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we will apply fresh-start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in Vanguard’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our Common Units and Preferred Units.

Our ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. Our ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or otherwise depart, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

Upon our emergence from bankruptcy, the composition of our Board changed significantly.

Pursuant to the Plan, the composition of our Board changed significantly. Upon emergence, our Board consisted of five members (the “Managers”). The new Managers have different backgrounds, experiences and perspectives from those individuals who previously served on Vanguard’s board of directors and, thus, may have different views on the issues that will determine our future. There is no guarantee that our new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.

Risks Related to Our Structure

Our limited liability company agreement limits our duties to our unitholders and restricts the remedies available to our unitholders for actions taken by us that might otherwise constitute breaches of duty.

Our limited liability agreement contains provisions that reduce the standards to which we might otherwise be held by state fiduciary duty law. For example, our limited liability company agreement:


•	provides that our Board and our managers and officers will not have any liability to us or our unitholders for decisions made so long as our Board or any manager or officer acted in good faith; and

•

provides that we and our officers and managers will not be liable to us or our unitholders for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining in respect of such matter or question that we or such other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Our unitholders are bound by the provisions in our liability company agreement, including those discussed above.

We may issue an unlimited number of additional units without common unitholder approval, which would dilute the ownership interest of existing unitholders.

Under our limited liability company agreement, we may, without the approval of our unitholders, issue an unlimited number of additional limited liability company interests of any type, including common units, without the approval of our unitholders.

The issuance by us of additional units or other equity securities may have the following effects:


•	our existing unitholders’ proportionate ownership interest in us may decrease;


•	the amount of cash available for distribution on each unit may decrease;


•	the relative voting strength of each previously outstanding unit may be diminished; and


•	the market price of our common units may decline.

Tax Risks to Unitholders

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

From time to time, legislation has been introduced in Congress which would eliminate certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

The consummation of the Plan may impair us from using our tax attributes (including NOL carryforwards) in future years.

Under U.S. federal income tax law, an entity taxed as a corporation (as we are) is generally permitted to deduct from taxable income net operating losses carried forward from prior years. However, when a corporation incurs cancellation of indebtedness income (“CODI”), as we did in connection with the consummation of the Plan, such CODI results in a reduction of tax attributes. Although we continue to evaluate the amount of CODI that we incurred as a result of the Plan, we currently expect that our tax attributes will be subject to significant reduction.

Additionally, to the extent any such tax attributes survive the reduction in tax attributes described above, our ability to utilize these tax attributes, and potentially to claim depreciation deductions (for a period of 5 years), to offset future taxable income and to reduce U.S. federal income tax liability will be subject to limitation under section 382 of the Internal Revenue Code, because we experienced an “ownership change” as a result of the consummation of the Plan. In general, as a result of this ownership change, our ability to utilize our pre-change attributes and, for five years, to claim certain depreciation deductions will be subject to certain limitations. Specifically, the amount of U.S. federal income tax attributes and, for five years, certain “built-in losses” existing prior to the change that we can utilize to offset its taxable income in future taxable years generally will generally be subject to an annual limitation based on the lesser of the value of our assets immediately prior to the consummation of the Plan and the value of our equity immediately after the consummation of the Plan, subject to adjustments to reflect the differences between the fair market value of the corporation’s assets and the tax basis in such assets and various other complex rules and adjustments.

The tax consequences of the Plan on our ability to utilize our tax attributes and claim certain depreciation deductions was described in greater detail in the disclosure statement we filed with the Bankruptcy Court.

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

~~None.~~On the Effective Date, the Company issued the following in accordance with the Plan:


•	39,063,570 Series A Preferred Units and 75,000 Series C Common Units were issued pro rata to holders of claims arising from the revolving credit facility provided under the RBL Credit Agreement and certain secured swaps;


•	5,975,091 Series A Preferred Units, 861,252 Series B Preferred Units and 10,000 Series C Common Units were issued pro rata to holders of claims arising from the Term Loan provided under the Term Loan Credit Agreement; and


•	700,000 Series A Preferred Units and 15,000 Series C Common Units were issued pro rata to holders of claims arising under the VNG Notes.

The Units will be issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act under Section 1145 of the Bankruptcy Code.

As of the Effective Date, there were 100,000 Series C Common Units, 45,738,661 Series A Preferred Units and 861,252 Series B Preferred Units issued and outstanding.

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~~VNG ~~Instruments~~Notes and VNG Credit Facility. Please see Note 32, “~~2019~~ Chapter 11 Proceedings” ~~under~~of ~~Item~~the 1.Notes ~~Unaudited~~to the Condensed Consolidated Financial Statements, included under Part I, Item 1 of this Quarterly Report for further discussion.

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 Quarterly Report.

ExhibitNumber		Description of Exhibit
2.1		~~Modified Second~~ Amended Joint Plan of Reorganization ~~under~~(as ~~Chapter~~Modified) 11 of ~~Bankruptcy Code of~~ Vanguard Natural Resources, ~~LLC~~Inc. and its Debtor Affiliates (incorporated by ~~reference~~referenced to Exhibit 2.1 to our ~~Predecessor’s~~ Current Report on Form 8-K filed July 1910, ~~2017~~2019)
3.1		~~Amended and Restated~~ Certificate of ~~Incorporation~~Conversion of Vanguard Natural Resources, Inc. (incorporated by ~~reference~~referenced to Exhibit 3.1 to our Current Report on Form 8-~~K15D5~~K filed ~~August~~July 217, ~~2017~~2019)
3.2		~~Amended~~Certificate ~~and~~of ~~Restated~~Formation ~~Bylaws~~ of ~~Vanguard~~Grizzly ~~Natural Resources~~Energy, ~~Inc.~~LLC (incorporated by ~~reference~~referenced to Exhibit 3.2 to our Current Report on Form 8-~~K15D5~~K filed ~~August~~July 217, ~~2017~~2019)
3.3		~~Certificate~~Limited ofLiability ~~Amendment~~Company asAgreement ~~filed~~of ~~with~~Grizzly ~~the~~Energy, ~~Delaware~~LLC ~~Secretary of State~~ (incorporated by ~~reference~~referenced to Exhibit 3.13 to our Current Report on Form 8-K/A filed ~~September~~August 2916, ~~2017~~2019)
10.1		~~Employment~~Fifth ~~Agreement~~Amended ~~with~~and ~~Richard~~Restated ~~Scott~~Credit ~~Sloan~~Agreement, dated ~~January~~as 22of July 16, 2019, among Grizzly Natural Gas, LLC, Grizzly Energy, LLC and Citibank, N.A., as Administrative Agent, Issuing Bank and Collateral Agent, and the Lenders Party Thereto (incorporated by ~~reference~~referenced to Exhibit 10.1 to our Current Report on Form 8-K filed ~~January~~July 2817, 2019)
10.2		~~Employment~~Term ~~Agreement~~Loan ~~with~~Credit ~~Ryan Midgett~~Agreement, dated ~~January~~as 22of July 16, 2019, among Grizzly Natural Gas, LLC, Grizzly Energy, LLC and Citibank, N.A., as Administrative Agent and Collateral Agent, and the Lenders Party Thereto (incorporated by ~~reference~~referenced to Exhibit 10.2 to our Current Report on Form 8-K filed ~~January~~July 2817, 2019)
10.3		~~Employment~~Collateral Agency Agreement, ~~with~~dated ~~Jonathan~~as C.of ~~Curth~~July 16, ~~dated~~2019, ~~January~~among 22Grizzly Natural Gas, ~~2019~~LLC, Citibank, N.A., as the First-Out Representative, Term B Representative and Collateral Agent (incorporated by ~~reference~~referenced to Exhibit 10.3 to our Current Report on Form 8-K filed ~~January~~July 2817, 2019)
10.4		~~Vanguard~~Unconditional ~~Natural~~Guaranty, ~~Resources~~dated as of July 16, ~~Inc~~2019, by Grizzly Energy, LLC, in favor of Citibank, N.A., ~~2019~~as ~~Short~~Administrative ~~Term~~Agent ~~Incentive~~for ~~Plan~~the Secured Parties under the Credit Agreement (incorporated by ~~reference~~referenced to Exhibit 10.214 to our ~~Annual~~Current Report on Form 108-K ~~for the year ended December 31, 2018,~~ filed onJuly ~~April 15~~17, 2019)
10.5		~~Vanguard~~Second ~~Natural~~Amended ~~Resources~~and Restated Unconditional Guaranty, ~~Inc.~~dated as of July 16, 2019, ~~Incentive~~by ~~Plan~~Grizzly Energy, LLC in favor of Citibank, N.A., as Administrative Agent for the Secured Parties under the Credit Agreement (incorporated by ~~reference~~referenced to Exhibit 10.225 to our ~~Annual~~Current Report on Form 108-K ~~for the year ended December 31, 2018,~~ filed onJuly ~~April 15~~17, 2019)
10.6		~~Ratification~~Second ~~and Fourth Amendment to Fourth~~ Amended and Restated ~~Credit~~Pledge and Security Agreement, dated ~~March~~as 31of July 16, 2019, among ~~Vanguard~~Grizzly Natural Gas, LLC, ~~Vanguard~~Grizzly ~~Natural~~Energy, ~~Resources~~LLC, ~~Inc.~~each of the Subsidiaries party thereto, in favor of Citibank, N.A., as ~~Administrative~~collateral ~~Agent~~agent ~~and lenders party thereto~~ (incorporated by ~~reference~~referenced to Exhibit 10.236 to our ~~Annual~~Current Report on Form 108-K ~~for the year ended December 31, 2018,~~ filed onJuly ~~April 15~~17, 2019)
10.7		~~First~~Amended ~~Amendment~~and toRestated ~~Debtor-in-Possession~~Employment ~~Credit~~ Agreement, ~~dated~~with asRichard ofScott ~~April 29~~Sloan, ~~2019,~~dated ~~among~~July ~~Vanguard Natural Gas~~16, ~~LLC,~~2019 ~~the Guarantors party thereto, the Administrative Agent, the Existing Lender and the New Lenders~~ (incorporated by ~~reference~~referenced to Exhibit 10.1 to our Current Report on Form 8-K filed ~~May~~July 317, 2019).
10.8		~~Plan~~Amended ~~Support~~and ~~Agreement,~~Restated ~~dated~~Employment asAgreement ofwith ~~May~~Ryan 8Midgett, ~~2019,~~dated ~~among~~July ~~the~~16, 2019 ~~Debtors and the Plan Support Parties~~ (incorporated by ~~reference~~referenced to Exhibit 10.12 to our Current Report on Form 8-K filed ~~May~~July 1317, 2019)
10.9		Amended and Restated Employment Agreement with Jonathan C. Curth, dated July 16, 2019 (incorporated by referenced to Exhibit 10.3 to our Current Report on Form 8-K filed July 17, 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



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.
		GRIZZLY ENERGY, LLC
		(Registrant)
	Date: May 15, 2019	/s/ Ryan Midgett
Date: August 19, 2019		/s/ Ryan Midgett
		Ryan Midgett
		Chief Financial Officer
		(Principal Financial Officer and Authorized Officer)

4549

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