10-Q

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 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:  000-55826

Grizzly Energy, 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:

Title of each class	Ticker symbol(s)	Name of each exchange on which registered
—	—	—

As of August 16, 2019, the 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	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	48

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

References in this report to “us,” “we,” “our” or the “Company” or like terms refer to (i) Vanguard Natural Resources, Inc. for the period prior to emergence from the Chapter 11 bankruptcy cases on July 16, 2019 (the “Effective Date”) and (ii) Grizzly Energy, LLC 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.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;

• the potential adverse effects of the consummation of the Plan (as defined herein) on our liquidity and results of operations;

• the impact of the Chapter 11 Cases on the liquidity and market price of our units and on our ability to access the public capital markets;

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

• the effects of the Bankruptcy Petitions on the Company and on the interests of various constituents, including holders of our Common and Preferred Units (as defined herein);

• the outcome of all other pending litigation;

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

• increased advisory costs and professional fees to implement the 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 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;

• 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;

• ability to execute our strategy 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.

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

GRIZZLY ENERGY, 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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Revenues:
Oil sales	$	37,150		$	46,503		$	69,897		$	92,614
Natural gas sales	29,132			42,623			91,446			97,890
NGLs sales	13,702			22,587			27,749			44,484
Oil, natural gas and NGLs sales	79,984			111,713			189,092			234,988
Net losses on commodity derivative contracts	(9,063		)	(45,332		)	(70,202		)	(63,917		)
Total revenues and losses on commodity derivative contracts	70,921			66,381			118,890			171,071
Costs and expenses:
Production:
Lease operating expenses	29,035			36,763			55,282			67,758
Transportation, gathering, processing and compression	8,484			9,768			18,006			21,270
Production and other taxes	7,833			7,971			17,656			17,752
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
Selling, general and administrative expenses	9,238			11,108			21,795			23,844
Total costs and expenses	417,097			112,303			511,599			233,273
Loss from operations	(346,176		)	(45,922		)	(392,709		)	(62,202		)
Other income (expense):
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 gain (loss) on divestitures of oil and natural gas properties	—			4,900			(458		)	4,900
Other	497			(175		)	586			(26		)
Total other expense, net	(1,183		)	(11,145		)	(18,527		)	(25,749		)
Loss before reorganization items	(347,359		)	(57,067		)	(411,236		)	(87,951		)
Reorganization items (Note 2)	(24,743		)	(610		)	(43,131		)	(2,317		)
Net loss	(372,102		)	(57,677		)	(454,367		)	(90,268		)
Less: Net income attributable to non-controlling interests	—			(96		)	—			(189		)
Net loss attributable to Common stockholders	$	(372,102	)	$	(57,773	)	$	(454,367	)	$	(90,457	)
Net loss per share – basic and diluted	$	(18.49	)	$	(2.87	)	$	(22.58	)	$	(4.50	)
Weighted average Common shares outstanding
Common shares – basic and diluted	20,124			20,100			20,124			20,100

See accompanying notes to condensed consolidated financial statements

3

GRIZZLY ENERGY, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

(Unaudited)

	June 30, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	44,782		$	33,538
Trade accounts receivable, net	42,892			62,073
Derivative assets	—			6,287
Restricted cash	4,449			4,450
Prepaid drilling costs	4,916			12,476
Other current assets	9,770			5,663
Total current assets	106,809			124,487
Oil and natural gas properties
Proved properties	1,574,565			1,567,903
Unproved properties	81,215			81,597
	1,655,780			1,649,500
Accumulated depletion, amortization and impairment	(661,137		)	(269,972		)
Oil and natural gas properties, net – successful efforts	994,643			1,379,528
Other assets
Lease assets	13,661			—
Derivative assets	—			6,766
Other assets	16,422			9,321
Total assets	$	1,131,535		$	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	23,371			12,175
Derivative liabilities	—			6,483
Oil and natural gas revenue payable	19,969			35,802
Long-term debt classified as current	—			879,181
Short-term debt	20,000			—
Other current liabilities	11,122			9,091
Total current liabilities	116,552			1,021,175
Long-term debt, net of current portion (Note 5)	—			5,446
Asset retirement obligations	141,019			139,433
Other long-term liabilities	8,020			523
Total liabilities not subject to compromise	265,591			1,166,577
Liabilities subject to compromise (Note 2)	965,605			—
Total liabilities	1,231,196			1,166,577
Commitments and contingencies (Note 10)
Stockholders’ equity (deficit) (Note 11)
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
Additional paid-in capital	510,067			508,886
Accumulated deficit	(609,748		)	(155,381		)
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

4

GRIZZLY ENERGY, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2019
	Common Stock			Additional Paid-in Capital		Accumulated Deficit			Total Stockholders’ Deficit
	Shares	Amount
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	)

	Six 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	—	—		—		(454,367		)	(454,367		)
Share-based compensation	—	—		1,181		—			1,181
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
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
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

5

GRIZZLY ENERGY, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
(in thousands)	2019			2018
Operating activities
Net loss	$	(454,367	)	$	(90,268	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	74,758			78,750
Impairment of oil and natural gas properties	323,626			22,153
Amortization of deferred financing costs	841			1,361
Share-based compensation	1,181			1,075
Net losses on commodity derivative contracts	70,202			63,917
Cash settlements paid on matured commodity derivative contracts	(9,762		)	(27,139		)
Net (gain) loss on divestiture of oil and natural gas properties	458			(4,900		)
Non-cash reorganization items (Note 2)	20,365			—
Changes in operating assets and liabilities:
Trade accounts receivable	18,723			14,124
Other current assets	(4,158		)	(1,357		)
Accounts payable and oil and natural gas revenue payable	(24,051		)	(136		)
Accrued expenses and other current liabilities	(2,666		)	(6,598		)
Other assets	(7,291		)	126
Net cash provided by operating activities	7,859			51,108
Investing activities
Additions to property and equipment	(39		)	(94		)
Additions to oil and natural gas properties	(6,801		)	(42,637		)
Deposits and prepayments of oil and natural gas properties	(7,086		)	(49,256		)
Proceeds from the sale of oil and natural gas properties	4,461			59,876
Net cash used in investing activities	(9,465		)	(32,111		)
Financing activities
Proceeds from long-term debt	—			90,000
Repayment of long-term debt	(7,145		)	(104,702		)
Proceeds from debtor-in-possession financing	20,000			—
Potato Hills distribution to non-controlling interest	—			(427		)
Financing fees	(6		)	(172		)
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	$	49,231		$	13,713
Supplemental cash flow information:
Cash paid for interest	$	9,937		$	29,988
Non-cash financing and investing activities:
Lease assets obtained in exchange for lease liabilities	$	182		$	—
Asset retirement obligations, net	$	251		$	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	$	44,782		$	7,502
Restricted cash at end of period	4,449			6,211
Cash and cash equivalents and restricted cash at end of period	$	49,231		$	13,713

See accompanying notes to condensed consolidated financial statements

6

GRIZZLY ENERGY, 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 maintain reserves, production and cash flow in a capital efficient manner while identifying opportunities to return cash to stakeholders. Through our operating subsidiaries, as of June 30, 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 “Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “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 Chapter 11 Cases were jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

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 and emerged from the Chapter 11 Cases. As part of the transactions undertaken pursuant to the Plan, Vanguard was converted from a Delaware corporation to a Delaware limited liability company and renamed Grizzly Energy, LLC (“Grizzly”). See Note 2 for a discussion of the Chapter 11 proceedings.

7

1.  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 June 30, 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 June 30, 2019 and December 31, 2018, and for the three and six months ended June 30, 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 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 are potentially 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.

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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

Vanguard was 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 June 30, 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. 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

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the expected credit losses on 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 incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. In May 2019, the FASB updated Topic 326 by issuing ASU 2019-05, Financial Instruments-Credit Losses (Topic 326): Targeted Transition Relief, which provides entities that have certain instruments within the scope of Subtopic 326-20, Financial Instruments-Credit Losses - Measured at Amortized Cost, with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments-Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The amendments in these Updates will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal 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.

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

2.     Chapter 11 Proceedings

Commencement of Bankruptcy Cases

On the Petition Date, the Debtors filed the Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court. The Debtors were jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

The subsidiary Debtors in the Chapter 11 Cases were GNG, GEH, GO, EOC, EAC, GAC, GUD, GAP, GAC II, GUD II and GAP II.

Reorganization Process

Throughout the Chapter 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 generally continued our operations without interruption during the pendency of the 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 authorized us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions 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 prohibited, for example, our lenders, 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, all of our prepetition liabilities and obligations were settled or compromised under the Bankruptcy Code through the Chapter 11 Cases.

Our 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.

Creditors’ Committees - Appointment & Formation

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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 consisted of the following three members: (i) Enterprise Jonah Gas Gathering LLC; (ii) Viva Energy Services LLC; and (iii) Trinity Environmental SWD I, LLC.

Schedules and Statements - Claims & Claims Resolution Process

On May 6, 2019 each of the 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 Debtors, including executory contracts to which each of the Debtors was a party, subject to the qualifications and assumptions included therein. The Schedules and Statements were subject to further amendment or modification after filing. Many of the claims identified in the Schedules and Statements were listed as disputed, contingent or unliquidated.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wished to assert prepetition claims against us and whose claim (i) were not listed in the Schedules and Statements or (ii) were listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to the bar 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 August 14, 2019, approximately 1,405 claims totaling $7.7 billion were filed with the Bankruptcy Court against the Debtors by approximately 1,206 claimants. We expect additional claims to be filed prior to the last bar 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 Debtors in the Chapter 11 Cases will be numerous. We expect the process of resolving claims filed against the Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with the Plan. As part of the process, we will work to resolve differences in amounts scheduled by the 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.

Plan Support Agreement

On May 8, 2019, the 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 “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.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on the Petition Date, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the 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 was Citibank N.A. The DIP Credit Agreement 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;

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• 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) (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);

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

• the DIP Credit Agreement 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 1.0% 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

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.

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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.

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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 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).

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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 VNG Credit Facility (as defined in Note 5). Accordingly, all amounts due under the VNG Credit Facility and VNG Notes (as defined in Note 5) (collectively, the “Debt Instruments”) were classified as current in the accompanying consolidated balance sheets as of that date.

The commencement of the Chapter 11 Cases was an event of default that accelerated the Debtors’ obligations under the following Debt Instruments:

• $677.7 million in unpaid principal with respect to the VNG Revolving Loan (defined in Note 5), $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 VNG Credit Facility; and

• $80.7 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the VNG Notes issued pursuant to the Amended and Restated 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 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 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 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. Rejections of contracts or leases, generally (1) were treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieved the Debtors of performing their future obligations under such contract or lease and (3) entitled the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. Assumption of executory contracts or unexpired leases, generally required the Company to cure any existing monetary defaults under such contract or lease and provide adequate assurance of

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future 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.

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 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 June 30, 2019 and 2018:

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

(1) Includes $14.1 million of accrued reorganization costs as of June 30, 2019 representing unpaid professional and legal fees directly related to the Chapter 11 Cases. Total payments made for professional and legal fees related to the 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 VNG Notes as these debt instruments were expected to be impacted by the bankruptcy reorganization process.

Going Concern

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 Chapter 11 Cases raised substantial doubt about our ability to

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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.

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.

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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 six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

4.  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 VNG Credit Facility (defined in Note 5, “Debt”).

5. Debt

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

Description	Interest Rate	Maturity Date	June 30, 2019			December 31, 2018
VNG Revolving Loan	Variable (1)	February 1, 2021	$	677,718		$	682,145
Term Loan	Variable (2)	May 1, 2021	123,438			123,438
New Money Facility	Variable (3)		20,000			—
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			$	901,878		$	889,635
Less:
Liabilities subject to compromise (Note 2)			(881,878		)	—
Short-term debt			(20,000		)	—
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 6.27% at December 31, 2018. In accordance with ASC 852, Reorganizations, we have accrued interest expense only up to the Petition Date.

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

(3) Variable interest rate of 7.92% at June 30, 2019. Borrowings under the New Money Facility were paid off prior to maturity on July 16, 2019 in connection with Grizzly’s emergence from the Chapter 11 Cases.

(4) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Liabilities” line item in the Balance Sheet. See Note 9, “Leases,” for a detailed discussion of 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

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As 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 are 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.

We accelerated the amortization of the remaining debt issue costs of $6.3 million associated with the Debt Instruments, fully amortizing those amounts as of the Petition Date. Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Debt Instruments. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Debt Instruments only up to the Petition Date. The total amount accrued of $12.5 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2019. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $15.7 million, representing interest expense from the Petition Date through June 30, 2019.

Additional information regarding the Chapter 11 cases is included in Note 2. Chapter 11 Cases.

VNG Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “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 VNG Credit Facility also included an additional $125.0 million senior secured term loan (the “Term Loan”). As of June 30, 2019, the 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.

VNG Notes

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.

Exit Facility

Grizzly has entered into the RBL Credit Agreement. Pursuant to the RBL Credit Agreement, the lenders party thereto agreed to provide the Revolving Loans and the Term Loan A. The initial borrowing base on the Revolving Loans is $65.0 million. The maturity date of the RBL Credit Agreement is July 16, 2022. The Company has also entered into that certain Term Loan Credit Agreement. 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 maturity date of the Term Loan Credit Agreement is January 16, 2023. See Note 2 for a detailed discussion of the Exit Facility.

6. Price Risk Management Activities

Historically, we entered into derivative contracts primarily with counterparties that were also lenders under our VNG Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. Our derivative 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 early termination of such derivative contracts. As a result of our defaults under our debt agreements and our 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 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 and was included in Liabilities Subject to Compromise on the Consolidated Balance Sheet as of June 30, 2019. The Company has not entered into any commodity derivative contracts subsequent to June 30, 2019.

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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 period indicated (in thousands):

	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 VNG Credit Facility (see Note 5, “Debt” for further discussion), which is secured by our oil and natural gas properties; therefore, we were not required to post any collateral. As of June 30, 2019, we had no outstanding commodity price or interest rate derivative contracts, and therefore no credit risk related to derivative instruments.

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

	Six Months Ended June 30, 2019			Year Ended December 31, 2018
Derivative asset (liability) at beginning of period, net	$	6,570		$	(64,437	)
Net losses on commodity derivative contracts	(70,202		)	(9,259		)
Cash settlements paid on matured commodity derivative contracts	9,762			80,266
Termination of commodity derivative contracts	53,870			—
Derivative asset at end of period, net	$	—		$	6,570

7.  Fair Value Measurements

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

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

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

The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six months ended June 30, 2019, we incurred impairment charges of $323.6 million as oil and natural gas properties with a net cost basis of $546.2 million were written down to their fair value of $222.6 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 six months ended June 30, 2018, we incurred impairment charges of $22.2 million as oil and natural gas properties with a net cost basis of $89.1 million were written down to their fair value of $66.9 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 as well 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.

8.  Asset Retirement Obligations

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

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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 six months ended June 30, 2019, we used credit-adjusted risk-free interest rate ranging from 6.3% to 6.8% and the average inflation factor was 1.6%.

9. Leases

We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets, other current liabilities and other long-term liabilities 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.

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.

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 June 30, 2019 were as follows (in thousands):

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		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

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 June 30, 2019 was as follows:

Leases (in thousands)	Classification	June 30, 2019
Assets
Operating lease assets	Lease assets	$	5,699
Finance lease assets, at cost	Lease assets	10,636
Accumulated amortization	Lease assets	(2,674		)
Finance lease assets, net	Lease assets	7,962
Total lease assets		$	13,661
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,116
Finance	Liabilities subject to compromise	5,183
Long-Term
Operating	Liabilities subject to compromise	5,051
Finance	Liabilities subject to compromise	2,969
Total lease liabilities		$	14,319

The maturity of our lease liabilities as of June 30, 2019 were as follows (in thousands):

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	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

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

	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

Rent expense for our office leases was $0.6 million and $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

As 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.

	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 June 30, 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 June 30, 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.

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	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 June 30, 2019, total estimated costs to be spent in 2019 is approximately $9.6 million, of which $2.5 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 were automatically stayed as to the Debtors through the Effective Date. Please see Note 2, “Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases.

11.  Stockholders’ Equity (Deficit)

Effect 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

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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 millionfor 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.

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14. Related Parties

One of the members of the Company’s Board, Kevin Asarnow, is also an Executive Director at RPA Advisors, LLC (“RPA”). RPA served as the financial advisor to the holders of allowed RBL Claims and allowed Secured Swap Claims during the Chapter 11 Cases. The Company incurred professional fees related to services provided by RPA of approximately $2.2 million for the six months ended June 30, 2019. We accrued professional services expense of $0.5 million for services rendered but not yet paid as of June 30, 2019.

Until August 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.

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

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2019 and 2018, and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report and with our 2018 Annual Report.

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

Overview

We are an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. We are currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to maintain reserves, production and cash flow in a capital efficient manner while identifying opportunities to return cash to stakeholders. Through our operating subsidiaries, as of June 30, 2019, we own properties and oil and natural gas reserves primarily located in nine operating basins:

• the Green River Basin in Wyoming;

• the Piceance Basin in Colorado;

• the Permian Basin in West Texas and New Mexico;

• the Arkoma Basin in Oklahoma;

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

• the Big Horn Basin in Wyoming and Montana;

• the Anadarko Basin in Oklahoma and North Texas;

• the Wind River Basin in Wyoming; and

• the Powder River Basin in Wyoming.

As of June 30, 2019, based on internal reserve estimates, our total estimated proved reserves were 955.1 Bcfe, of which approximately 64% were natural gas reserves, 19% were oil reserves and 17% 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 June 30, 2019, we owned working interests in 10,424 gross (3,674 net) productive wells. Our operated wells accounted for approximately 59% of our total estimated proved reserves at June 30, 2019. Our average net daily production for the six months ended June 30, 2019 and the year ended December 31, 2018 was 296 MMcfe/day and 346 MMcfe/day, respectively.

We develop an annual capital expenditures budget which is reviewed and approved by our 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 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 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

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unilaterally terminated all derivative contracts to which we were a party. We currently have no commodity derivative contracts in place.

Bankruptcy Proceedings under Chapter 11

Commencement of Bankruptcy Cases

On March 31, 2019 (the “Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “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 Debtors were jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

Plan Support Agreement

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

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on the Petition Date, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the 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. The initial lender under the DIP Credit Agreement was Citibank N.A. The DIP Credit Agreement 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 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”);

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

• the DIP Credit Agreement 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

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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

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. Capitalized terms used but not defined in this Quarterly Report are defined in 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; 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.

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

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(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

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

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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 Company and 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. Rejection of an executory contract or unexpired lease was generally treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company and the Chapter 11 Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may have given rise to a 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 Plan, as continued, does not provide any economic recovery to holders of our existing common stock. Please read Note 2, “Chapter 11 Proceedings” of the Notes to the Condensed Consolidated Financial Statements for further discussion on plan provisions.

Reorganization Expenses

The 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.

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.

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 $21.5 million during the six months ended June 30, 2019. While we have sufficient access to capital, we are currently undertaking a review of our capital expenditures opportunities in conjunction with other opportunities to improve stakeholder value for the balance of 2019 and beyond. However, we anticipate that we are committed to spend approximately $5.0 million on operated capital projects and approximately $10.2 million on non-operated capital projects over the balance of 2019.

During the six months ended June 30, 2019, we participated in the drilling of 58 gross (10.6 net) non-operated wells and in the completion of 31 gross (4.3 net) non-operated wells.

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Results of Operations

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Revenues:
Oil sales	$	37,150		$	46,503		$	69,897		$	92,614
Natural gas sales	29,132			42,623			91,446			97,890
NGLs sales	13,702			22,587			27,749			44,484
Oil, natural gas and NGLs sales	79,984			111,713			189,092			234,988
Net losses on commodity derivative contracts	(9,063		)	(45,332		)	(70,202		)	(63,917		)
Total revenues and losses on commodity derivative contracts	$	70,921		$	66,381		$	118,890		$	171,071
Costs and expenses:
Production:
Lease operating expenses	29,035			36,763			55,282			67,758
Transportation, gathering, processing and compression	8,484			9,768			18,006			21,270
Production and other taxes	7,833			7,971			17,656			17,752
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
Selling, general and administrative expenses	8,648			10,529			20,614			22,769
Share-based compensation	590			579			1,181			1,075
Total costs and expenses	$	417,097		$	112,303		$	511,599		$	233,273
Other income (expense):
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 gain (loss) on divestitures of oil and natural gas properties	—			4,900			(458		)	4,900
Other	497			(175		)	586			(26		)
Reorganization items	(24,743		)	(610		)	(43,131		)	(2,317		)

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

Revenues

Oil, natural gas and NGLs sales were $80.0 million and $111.7 million for the three months ended June 30, 2019 and 2018, respectively. The key oil, natural gas and NGLs revenue measurements were as follows:

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	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.

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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 decreased by $7.7 million to $29.0 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 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. Overall, spending during the three months ended June 30, 2019 decreased as compared to the same period in 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 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 $8.5 million for the three months ended June 30, 2019, which represents a decrease from the $9.8 million recorded during the three 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. Production and other taxes decreased slightly by $0.1 million for the three months ended June 30, 2019 as compared to the same period in 2018.

Depreciation, depletion, amortization, and accretion increased by approximately $0.3 million to $39.0 million for the three months ended June 30, 2019 from approximately $38.7 million for the three months ended June 30, 2018, primarily due to a higher depletion rate resulting from lower estimates of oil and natural gas 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 $323.2 million and $7.6 million was recognized during the three months ended June 30, 2019 and 2018, respectively. The impairment charge recognized during the three months ended June 30, 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 primarily relate to downward revisions of 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 $0.4 million during the three months ended June 30, 2018 to $0.3 million for the three 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 three

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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 $1.7 million and $15.9 million during the three months ended June 30, 2019 and 2018, respectively. As of the Petition Date, we discontinued recording interest on debt classified as liabilities subject to compromise, which resulted in the decrease in interest expense during 2019.

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. 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

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(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.

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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 Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’

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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 addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 Cases and expect that we may continue to incur significant professional fees and costs following our emergence from the Chapter 11 Cases.

Liquidity Following Emergence from the Chapter 11 Cases

As of July 16, 2019, Grizzly emerged from the Chapter 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.

Statements of Cash Flows

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

	Six Months Ended
	June 30,
	2019			2018
Net cash provided by operating activities	$	7,859		$	51,108
Net cash used in investing activities	$	(9,465	)	$	(32,111	)
Net cash provided by (used in) financing activities	$	12,849		$	(15,301	)

Cash Flow from Operations

Net cash provided by operating activities was approximately $7.9 million for the six months ended June 30, 2019 compared to $51.1 million for the six months ended June 30, 2018. Changes in working capital decreased total cash flow by $19.4 million for the six months ended June 30, 2019, and increased total cash flow by $6.2 million for the six months ended June 30, 2018. Contributing to the decrease in working capital during the first 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 six months of 2018, the increase in working capital resulted from a $14.1 million decrease in accounts receivable related to the timing of receipts from production, offset by a $6.7 milliondecrease 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. Historically, we have entered into derivative contracts to reduce the impact of commodity price volatility on operations. We have primarily used fixed-price swaps, collars, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. In April 2019, our derivative contract counterparties unilaterally terminated all derivative contracts to which we were a party. We currently have no commodity derivative contracts in place.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $9.5 million for the six months ended June 30, 2019 compared to approximately $32.1 million for the six months ended June 30, 2018. Net cash used in investing activities during the first six months ended of 2019 primarily included $6.8 million for the drilling and development of oil and natural gas properties

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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 provided by financing activities was approximately $12.8 million for the six months ended June 30, 2019 compared to net cash used in financing activities of approximately $15.3 million for the six months ended June 30, 2018. Net cash provided by financing activities during the six months ended June 30, 2019 included proceeds from debtor-in-possession financing of $20.0 million, offset by repayments of debt of $7.1 million. During the six months ended June 30, 2018, net cash used in financing activities primarily included repayments of our revolving credit facility and term loan of $104.7 million, offset by the proceeds from our revolving credit facility of $90.0 million.

VNG Credit Facility and Notes

Acceleration of Debt Obligations

As 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.

We accelerated the amortization of the remaining debt issue costs of $6.3 million associated with the Debt Instruments, fully amortizing those amounts as of the Petition Date. Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Debt Instruments. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Debt Instruments only up to the Petition Date. The total amount accrued of $12.5 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2019. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $15.7 million, representing interest expense from the Petition Date through June 30, 2019.

VNG Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “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 VNG Credit Facility also included an additional $125.0 million senior secured term loan (the “Term Loan”). As of June 30, 2019, the 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.

VNG Notes

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.

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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 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 in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard stockholders 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;

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• Change in fair value of commodity derivative contracts;

• Termination of commodity derivative contracts;

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

• Share-based compensation expense;

• Reorganization items;

• Severance 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.

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.

Adjusted 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):

	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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net cash settlements paid on matured commodity derivative    contracts	$	—		$	(17,847	)	$	(9,762	)	$	(27,139	)
Loss on matured commodity derivative contracts not settled	—			—			(6,327		)	—
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 June 30, 2019 at the reasonable assurance level.     

Changes in Internal Control over Financial Reporting

In April 2019, we outsourced 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 controls over financial reporting to ensure we receive accurate data from Concord as it relates to our revenues, commodity pricing and production volumes as well as the related gathering, transportation and marketing fees.

There 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.

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PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

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

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

Pursuant to 11 U.S.C. § 362, with certain exceptions, our legal proceedings were automatically stayed as to the Debtors 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.

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:

We recently emerged from bankruptcy, which may adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from bankruptcy may adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

• key suppliers, vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;

• our ability to renew existing contracts and compete for new business may be adversely affected;

• our ability to attract, motivate and/or retain key executives and employees may be adversely affected;

• employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

• competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The 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.

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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.

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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

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.

46

Item 3.  Defaults Upon Senior Securities

As described herein, the commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the VNG Notes and VNG Credit Facility. 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.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

47

Item 6.  Exhibits

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

Exhibit Number	Description of Exhibit
2.1	Amended Joint Plan of Reorganization (as Modified) of Vanguard Natural Resources, Inc. and its Debtor Affiliates (incorporated by referenced to Exhibit 2.1 to our Current Report on Form 8-K filed July 10, 2019)
3.1	Certificate of Conversion of Vanguard Natural Resources, Inc. (incorporated by referenced to Exhibit 3.1 to our Current Report on Form 8-K filed July 17, 2019)
3.2	Certificate of Formation of Grizzly Energy, LLC (incorporated by referenced to Exhibit 3.2 to our Current Report on Form 8-K filed July 17, 2019)
3.3	Limited Liability Company Agreement of Grizzly Energy, LLC (incorporated by referenced to Exhibit 3.3 to our Current Report on Form 8-K/A filed August 16, 2019)
10.1	Fifth Amended and Restated Credit Agreement, dated as of 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 referenced to Exhibit 10.1 to our Current Report on Form 8-K filed July 17, 2019)
10.2	Term Loan Credit Agreement, dated as of 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 referenced to Exhibit 10.2 to our Current Report on Form 8-K filed July 17, 2019)
10.3	Collateral Agency Agreement, dated as of July 16, 2019, among Grizzly Natural Gas, LLC, Citibank, N.A., as the First-Out Representative, Term B Representative and Collateral Agent (incorporated by referenced to Exhibit 10.3 to our Current Report on Form 8-K filed July 17, 2019)
10.4	Unconditional Guaranty, dated as of July 16, 2019, by Grizzly Energy, LLC, in favor of Citibank, N.A., as Administrative Agent for the Secured Parties under the Credit Agreement (incorporated by referenced to Exhibit 10.4 to our Current Report on Form 8-K filed July 17, 2019)
10.5	Second Amended and Restated Unconditional Guaranty, dated as of July 16, 2019, by Grizzly Energy, LLC in favor of Citibank, N.A., as Administrative Agent for the Secured Parties under the Credit Agreement (incorporated by referenced to Exhibit 10.5 to our Current Report on Form 8-K filed July 17, 2019)
10.6	Second Amended and Restated Pledge and Security Agreement, dated as of July 16, 2019, among Grizzly Natural Gas, LLC, Grizzly Energy, LLC, each of the Subsidiaries party thereto, in favor of Citibank, N.A., as collateral agent (incorporated by referenced to Exhibit 10.6 to our Current Report on Form 8-K filed July 17, 2019)
10.7	Amended and Restated Employment Agreement with Richard Scott Sloan, dated July 16, 2019 (incorporated by referenced to Exhibit 10.1 to our Current Report on Form 8-K filed July 17, 2019)
10.8	Amended and Restated Employment Agreement with Ryan Midgett, dated July 16, 2019 (incorporated by referenced to Exhibit 10.2 to our Current Report on Form 8-K filed July 17, 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.

48

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.

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

49

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, R. Scott Sloan, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Grizzly Energy, LLC (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 19, 2019

/s/ R. Scott Sloan

R. Scott Sloan 

President and Chief Executive Officer

(Principal Executive Officer)

Grizzly Energy, LLC

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Ryan Midgett, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Grizzly Energy, LLC (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 19, 2019

/s/ Ryan Midgett

Ryan Midgett

Chief Financial Officer

(Principal Financial Officer)

Grizzly Energy, LLC 

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Grizzly Energy, LLC (the “Company”) on Form 10-Q for the period ended June 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Scott Sloan, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1.     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.     The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ R. Scott Sloan

R. Scott Sloan

President and Chief Executive Officer

(Principal Executive Officer)

August 19, 2019

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Grizzly Energy, LLC (the “Company”) on Form 10-Q for the period ended June 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ryan Midgett, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Ryan Midgett

Ryan Midgett

Chief Financial Officer
(Principal Financial Officer)
 

August 19, 2019

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 16, 2019
Document Information [Line Items]
Entity Registrant Name	Grizzly Energy, LLC
Entity Central Index Key	0001384072
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Small Business	true
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Current Reporting Status	Yes
Common Class C
Document Information [Line Items]
Entity Common Shares, Shares Outstanding		100,000
Series A Preferred Stock
Document Information [Line Items]
Entity Common Shares, Shares Outstanding		45,738,661
Series B Preferred Stock
Document Information [Line Items]
Entity Common Shares, Shares Outstanding		861,252

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues:
Net losses on commodity derivative contracts	$ (9,063)	$ (45,332)	$ (70,202)	$ (63,917)
Total revenues and losses on commodity derivative contracts	70,921	66,381	118,890	171,071
Production:
Lease operating expenses	29,035	36,763	55,282	67,758
Production and other taxes	7,833	7,971	17,656	17,752
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
Selling, general and administrative expenses	9,238	11,108	21,795	23,844
Total costs and expenses	417,097	112,303	511,599	233,273
Loss from operations	(346,176)	(45,922)	(392,709)	(62,202)
Other income (expense):
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 gain (loss) on divestitures of oil and natural gas properties	0	4,900	(458)	4,900
Other	497	(175)	586	(26)
Total other expense, net	(1,183)	(11,145)	(18,527)	(25,749)
Loss before reorganization items	(347,359)	(57,067)	(411,236)	(87,951)
Reorganization items (Note 2)	(24,743)	(610)	(43,131)	(2,317)
Net loss	(372,102)	(57,677)	(454,367)	(90,268)
Less: Net income attributable to non-controlling interests	0	(96)	0	(189)
Net loss attributable to Common stockholders	$ (372,102)	$ (57,773)	$ (454,367)	$ (90,457)
Net income (loss) per share/unit – basic and diluted (USD per share)	$ (18.49)	$ (2.87)	$ (22.58)	$ (4.50)
Common Stock
Weighted average Common shares outstanding
Weighted average Common shares/units outstanding – basic and diluted (in shares)	20,124	20,100	20,124	20,100
Oil sales
Revenues:
Oil, natural gas and NGLs sales	$ 37,150	$ 46,503	$ 69,897	$ 92,614
Natural gas sales
Revenues:
Oil, natural gas and NGLs sales	29,132	42,623	91,446	97,890
NGLs sales
Revenues:
Oil, natural gas and NGLs sales	13,702	22,587	27,749	44,484
Oil, natural gas and NGLs sales
Revenues:
Oil, natural gas and NGLs sales	79,984	111,713	189,092	234,988
Transportation, gathering, processing and compression
Production:
Transportation, gathering, processing and compression	$ 8,484	$ 9,768	$ 18,006	$ 21,270

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Income Statement [Abstract]
Interest Expense	$ 15.7	$ 15.7

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 44,782	$ 33,538
Trade accounts receivable, net	42,892	62,073
Derivative assets	0	6,287
Restricted cash	4,449	4,450
Prepaid drilling costs	4,916	12,476
Other current assets	9,770	5,663
Total current assets	106,809	124,487
Oil and natural gas properties
Proved properties	1,574,565	1,567,903
Unproved properties	81,215	81,597
Oil and natural gas properties, gross - successful effort method	1,655,780	1,649,500
Accumulated depletion, amortization and impairment	(661,137)	(269,972)
Oil and natural gas properties, net – successful efforts	994,643	1,379,528
Other assets
Lease assets	13,661
Derivative assets	0	6,766
Other assets	16,422	9,321
Total assets	1,131,535	1,520,102
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	23,371	12,175
Derivative liabilities	0	6,483
Oil and natural gas revenue payable	19,969	35,802
Long-term debt classified as current	0	879,181
Short-term debt	20,000	0
Other current liabilities	11,122	9,091
Total current liabilities	116,552	1,021,175
Long-term debt, net of current portion (Note 5)	0	5,446
Asset retirement obligations	141,019	139,433
Other long-term liabilities	8,020	523
Total liabilities not subject to compromise	265,591	1,166,577
Liabilities subject to compromise (Note 2)	965,605	0
Total liabilities	1,231,196	1,166,577
Commitments and contingencies (Note 10)
Stockholders’ equity (deficit) (Note 11)
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
Additional paid-in capital	510,067	508,886
Accumulated deficit	(609,748)	(155,381)
Total stockholders’ equity (deficit)	(99,661)	353,525
Total liabilities and equity (deficit)	$ 1,131,535	$ 1,520,102

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common stock, par value (usd per share)	$ 0.001	$ 0.001
Common stock, authorized (shares)	50,000,000	50,000,000
Common stock, issued (shares)	20,124,081	20,124,080
Common stock, outstanding (shares)	20,124,081	20,124,080

XML

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) (Unaudited) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Non-controlling Interest
Beginning balance (shares) at Dec. 31, 2017		20,100,000
Beginning balance at Dec. 31, 2017	$ 397,528	$ 20	$ 506,640	$ (111,410)	$ 2,278
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(90,268)			(90,457)	189
Share-based compensation	1,075		1,075
Potato Hills cash distribution to non-controlling interest	(427)				(427)
Ending balance (shares) at Jun. 30, 2018		20,100,000
Ending balance at Jun. 30, 2018	307,908	$ 20	507,715	(201,867)	2,040
Beginning balance (shares) at Mar. 31, 2018		20,100,000
Beginning balance at Mar. 31, 2018	365,256	$ 20	507,136	(144,094)	2,194
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(57,677)			(57,773)	96
Share-based compensation	579		579
Potato Hills cash distribution to non-controlling interest	(250)				(250)
Ending balance (shares) at Jun. 30, 2018		20,100,000
Ending balance at Jun. 30, 2018	$ 307,908	$ 20	507,715	(201,867)	$ 2,040
Beginning balance (shares) at Dec. 31, 2018	20,124,080	20,124,000
Beginning balance at Dec. 31, 2018	$ 353,525	$ 20	508,886	(155,381)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(454,367)			(454,367)
Share-based compensation	$ 1,181		1,181
Ending balance (shares) at Jun. 30, 2019	20,124,081	20,124,000
Ending balance at Jun. 30, 2019	$ (99,661)	$ 20	510,067	(609,748)
Beginning balance (shares) at Mar. 31, 2019		20,124,000
Beginning balance at Mar. 31, 2019	271,851	$ 20	509,477	(237,646)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(372,102)			(372,102)
Share-based compensation	$ 590		590
Ending balance (shares) at Jun. 30, 2019	20,124,081	20,124,000
Ending balance at Jun. 30, 2019	$ (99,661)	$ 20	$ 510,067	$ (609,748)

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Operating activities
Net loss	$ (372,102)	$ (57,677)	$ (454,367)	$ (90,268)
Adjustments to reconcile net loss to net cash provided by operating activities:
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
Amortization of deferred financing costs			841	1,361
Share-based compensation			1,181	1,075
Net losses on commodity derivative contracts			70,202	63,917
Cash settlements paid on matured commodity derivative contracts			(9,762)	(27,139)	$ (80,266)
Net (gain) loss on divestiture of oil and natural gas properties	0	(4,900)	458	(4,900)
Non-cash reorganization items (Note 2)			20,365	0
Changes in operating assets and liabilities:
Trade accounts receivable			18,723	14,124
Other current assets			(4,158)	(1,357)
Accounts payable and oil and natural gas revenue payable			(24,051)	(136)
Accrued expenses and other current liabilities			(2,666)	(6,598)
Other assets			(7,291)	126
Net cash provided by operating activities			7,859	51,108
Investing activities
Additions to property and equipment			(39)	(94)
Additions to oil and natural gas properties			(6,801)	(42,637)
Deposits and prepayments of oil and natural gas properties			(7,086)	(49,256)
Proceeds from the sale of oil and natural gas properties			4,461	59,876
Net cash used in investing activities			(9,465)	(32,111)
Financing activities
Proceeds from long-term debt			0	90,000
Repayment of long-term debt			(7,145)	(104,702)
Proceeds from debtor-in-possession financing			20,000	0
Potato Hills distribution to non-controlling interest			0	(427)
Financing fees			(6)	(172)
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	10,017
Cash, cash equivalents and restricted cash, end of period	49,231	13,713	49,231	13,713	37,988
Supplemental cash flow information:
Cash paid for interest			9,937	29,988
Non-cash financing and investing activities:
Lease assets obtained in exchange for lease liabilities			182	0
Asset retirement obligations, net			251	12,294
Reconciliation of Cash and Cash Equivalents and Restricted Cash
Cash and cash equivalents						$ 44,782	$ 33,538	$ 7,502	$ 2,762
Restricted cash						4,449	4,450	6,211	7,255
Cash and cash equivalents and restricted cash at end of period	$ 49,231	$ 13,713	$ 37,988	$ 10,017	$ 10,017	$ 49,231	$ 37,988	$ 13,713	$ 10,017

XML

General

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

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 maintain reserves, production and cash flow in a capital efficient manner while identifying opportunities to return cash to stakeholders. Through our operating subsidiaries, as of June 30, 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 “Petition Date”), the Company and its subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “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 Chapter 11 Cases were jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

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 and emerged from the Chapter 11 Cases. As part of the transactions undertaken pursuant to the Plan, Vanguard was converted from a Delaware corporation to a Delaware limited liability company and renamed Grizzly Energy, LLC (“Grizzly”). See Note 2 for a discussion of the Chapter 11 proceedings.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

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 June 30, 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 June 30, 2019 and December 31, 2018, and for the three and six months ended June 30, 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 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 are potentially 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.

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

Vanguard was 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 June 30, 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. 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 expected credit losses on 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 incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. In May 2019, the FASB updated Topic 326 by issuing ASU 2019-05, Financial Instruments-Credit Losses (Topic 326): Targeted Transition Relief, which provides entities that have certain instruments within the scope of Subtopic 326-20, Financial Instruments-Credit Losses - Measured at Amortized Cost, with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments-Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The amendments in these Updates will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal 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.

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

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Chapter 11 Proceedings

6 Months Ended

Jun. 30, 2019

Reorganizations [Abstract]

Chapter 11 Proceedings

Chapter 11 Proceedings

Commencement of Bankruptcy Cases

On the Petition Date, the Debtors filed the Chapter 11 Cases under the Bankruptcy Code in the Bankruptcy Court. The Debtors were jointly administered under the caption “In re Vanguard Natural Resources, Inc., et al.”

The subsidiary Debtors in the Chapter 11 Cases were GNG, GEH, GO, EOC, EAC, GAC, GUD, GAP, GAC II, GUD II and GAP II.

Reorganization Process

Throughout the Chapter 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 generally continued our operations without interruption during the pendency of the 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 authorized us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions 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 prohibited, for example, our lenders, 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, all of our prepetition liabilities and obligations were settled or compromised under the Bankruptcy Code through the Chapter 11 Cases.

Our 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.

Creditors’ Committees - Appointment & Formation

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 consisted of the following three members: (i) Enterprise Jonah Gas Gathering LLC; (ii) Viva Energy Services LLC; and (iii) Trinity Environmental SWD I, LLC.

Schedules and Statements - Claims & Claims Resolution Process

On May 6, 2019 each of the 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 Debtors, including executory contracts to which each of the Debtors was a party, subject to the qualifications and assumptions included therein. The Schedules and Statements were subject to further amendment or modification after filing. Many of the claims identified in the Schedules and Statements were listed as disputed, contingent or unliquidated.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wished to assert prepetition claims against us and whose claim (i) were not listed in the Schedules and Statements or (ii) were listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to the bar 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 August 14, 2019, approximately 1,405 claims totaling $7.7 billion were filed with the Bankruptcy Court against the Debtors by approximately 1,206 claimants. We expect additional claims to be filed prior to the last bar 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 Debtors in the Chapter 11 Cases will be numerous. We expect the process of resolving claims filed against the Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with the Plan. As part of the process, we will work to resolve differences in amounts scheduled by the 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.

Plan Support Agreement

On May 8, 2019, the 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 “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.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on the Petition Date, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the 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 was Citibank N.A. The DIP Credit Agreement 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 VNG Credit Facility (as defined in Note 5) (the “Roll-Up”, and, together with the New Money Facility, collectively, the “DIP Facility”);

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

• the DIP Credit Agreement 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 1.0% 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

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 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 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 VNG Credit Facility (as defined in Note 5). Accordingly, all amounts due under the VNG Credit Facility and VNG Notes (as defined in Note 5) (collectively, the “Debt Instruments”) were classified as current in the accompanying consolidated balance sheets as of that date.

The commencement of the Chapter 11 Cases was an event of default that accelerated the Debtors’ obligations under the following Debt Instruments:

• $677.7 million in unpaid principal with respect to the VNG Revolving Loan (defined in Note 5), $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 VNG Credit Facility; and

• $80.7 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the VNG Notes issued pursuant to the Amended and Restated 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 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 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 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. Rejections of contracts or leases, generally (1) were treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieved the Debtors of performing their future obligations under such contract or lease and (3) entitled the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. Assumption of executory contracts or unexpired leases, 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. 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.

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 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 June 30, 2019 and 2018:

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

(1) Includes $14.1 million of accrued reorganization costs as of June 30, 2019 representing unpaid professional and legal fees directly related to the Chapter 11 Cases. Total payments made for professional and legal fees related to the 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 VNG Notes as these debt instruments were expected to be impacted by the bankruptcy reorganization process.

Going Concern

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 Chapter 11 Cases raised 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 adjustments as a result of this substantial doubt.

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Revenues

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenues

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.

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 six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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Divestitures

6 Months Ended

Jun. 30, 2019

Business Combinations [Abstract]

Divestitures

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 VNG Credit Facility (defined in Note 5, “Debt”).

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Debt

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt

Debt

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

Description	Interest Rate	Maturity Date	June 30, 2019			December 31, 2018
VNG Revolving Loan	Variable (1)	February 1, 2021	$	677,718		$	682,145
Term Loan	Variable (2)	May 1, 2021	123,438			123,438
New Money Facility	Variable (3)		20,000			—
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			$	901,878		$	889,635
Less:
Liabilities subject to compromise (Note 2)			(881,878		)	—
Short-term debt			(20,000		)	—
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 6.27% at December 31, 2018. In accordance with ASC 852, Reorganizations, we have accrued interest expense only up to the Petition Date.

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

(3) Variable interest rate of 7.92% at June 30, 2019. Borrowings under the New Money Facility were paid off prior to maturity on July 16, 2019 in connection with Grizzly’s emergence from the Chapter 11 Cases.

(4) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Liabilities” line item in the Balance Sheet. See Note 9, “Leases,” for a detailed discussion of 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 VNG 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 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.

We accelerated the amortization of the remaining debt issue costs of $6.3 million associated with the Debt Instruments, fully amortizing those amounts as of the Petition Date. Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Debt Instruments. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Debt Instruments only up to the Petition Date. The total amount accrued of $12.5 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2019. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $15.7 million, representing interest expense from the Petition Date through June 30, 2019.

Additional information regarding the Chapter 11 cases is included in Note 2. Chapter 11 Cases.

VNG Credit Facility

Under the Company’s Fourth Amended and Restated Credit Agreement (the “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 VNG Credit Facility also included an additional $125.0 million senior secured term loan (the “Term Loan”). As of June 30, 2019, the 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.

VNG Notes

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.

Exit Facility

Grizzly has entered into the RBL Credit Agreement. Pursuant to the RBL Credit Agreement, the lenders party thereto agreed to provide the Revolving Loans and the Term Loan A. The initial borrowing base on the Revolving Loans is $65.0 million. The maturity date of the RBL Credit Agreement is July 16, 2022. The Company has also entered into that certain Term Loan Credit Agreement. 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 maturity date of the Term Loan Credit Agreement is January 16, 2023. See Note 2 for a detailed discussion of the Exit Facility.

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Price Risk Management Activities

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Price Risk Management Activities

Price Risk Management Activities

Historically, we entered into derivative contracts primarily with counterparties that were also lenders under our VNG Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. Our derivative 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 early termination of such derivative contracts. As a result of our defaults under our debt agreements and our 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 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 and was included in Liabilities Subject to Compromise on the Consolidated Balance Sheet as of June 30, 2019. The Company has not entered into any commodity derivative contracts subsequent to June 30, 2019.

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 period indicated (in thousands):

	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 VNG Credit Facility (see Note 5, “Debt” for further discussion), which is secured by our oil and natural gas properties; therefore, we were not required to post any collateral. As of June 30, 2019, we had no outstanding commodity price or interest rate derivative contracts, and therefore no credit risk related to derivative instruments.

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

	Six Months Ended June 30, 2019			Year Ended December 31, 2018
Derivative asset (liability) at beginning of period, net	$	6,570		$	(64,437	)
Net losses on commodity derivative contracts	(70,202		)	(9,259		)
Cash settlements paid on matured commodity derivative contracts	9,762			80,266
Termination of commodity derivative contracts	53,870			—
Derivative asset at end of period, net	$	—		$	6,570

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Fair Value Measurements

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

	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 six months ended June 30, 2019, we incurred impairment charges of $323.6 million as oil and natural gas properties with a net cost basis of $546.2 million were written down to their fair value of $222.6 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 six months ended June 30, 2018, we incurred impairment charges of $22.2 million as oil and natural gas properties with a net cost basis of $89.1 million were written down to their fair value of $66.9 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 as well 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.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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	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 six months ended June 30, 2019, we used credit-adjusted risk-free interest rate ranging from 6.3% to 6.8% and the average inflation factor was 1.6%.

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Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Leases

Leases

We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets, other current liabilities and other long-term liabilities 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.

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.

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 June 30, 2019 were as follows (in thousands):

		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

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 June 30, 2019 was as follows:

Leases (in thousands)	Classification	June 30, 2019
Assets
Operating lease assets	Lease assets	$	5,699
Finance lease assets, at cost	Lease assets	10,636
Accumulated amortization	Lease assets	(2,674		)
Finance lease assets, net	Lease assets	7,962
Total lease assets		$	13,661
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,116
Finance	Liabilities subject to compromise	5,183
Long-Term
Operating	Liabilities subject to compromise	5,051
Finance	Liabilities subject to compromise	2,969
Total lease liabilities		$	14,319

The maturity of our lease liabilities as of June 30, 2019 were 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

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

	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

Rent expense for our office leases was $0.6 million and $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.

Leases

Leases

We determine if an arrangement is a lease at inception. Operating leases and finance leases are included in lease assets, other current liabilities and other long-term liabilities 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.

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.

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 June 30, 2019 were as follows (in thousands):

		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

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 June 30, 2019 was as follows:

Leases (in thousands)	Classification	June 30, 2019
Assets
Operating lease assets	Lease assets	$	5,699
Finance lease assets, at cost	Lease assets	10,636
Accumulated amortization	Lease assets	(2,674		)
Finance lease assets, net	Lease assets	7,962
Total lease assets		$	13,661
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,116
Finance	Liabilities subject to compromise	5,183
Long-Term
Operating	Liabilities subject to compromise	5,051
Finance	Liabilities subject to compromise	2,969
Total lease liabilities		$	14,319

The maturity of our lease liabilities as of June 30, 2019 were 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

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

	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

Rent expense for our office leases was $0.6 million and $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.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Lease Commitments

As 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.

	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 June 30, 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 June 30, 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.

	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 June 30, 2019, total estimated costs to be spent in 2019 is approximately $9.6 million, of which $2.5 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 were automatically stayed as to the Debtors through the Effective Date. Please see Note 2, “Chapter 11 Proceedings,” for information regarding our Chapter 11 Cases.

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Stockholders’ Equity (Deficit)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

Stockholders’ Equity (Deficit)

Stockholders’ Equity (Deficit)

Effect 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.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2019

Share-based Payment Arrangement [Abstract]

Share-Based Compensation

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 millionfor 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.

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Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

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.

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Related Parties (Notes)

6 Months Ended

Jun. 30, 2019

Related Party Transactions [Abstract]

Related Parties

Related Parties

One of the members of the Company’s Board, Kevin Asarnow, is also an Executive Director at RPA Advisors, LLC (“RPA”). RPA served as the financial advisor to the holders of allowed RBL Claims and allowed Secured Swap Claims during the Chapter 11 Cases. The Company incurred professional fees related to services provided by RPA of approximately $2.2 million for the six months ended June 30, 2019. We accrued professional services expense of $0.5 million for services rendered but not yet paid as of June 30, 2019.

Until August 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.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Principles of Consolidation

Basis of Presentation and Principles of Consolidation

The condensed consolidated financial statements as of June 30, 2019 and December 31, 2018, and for the three and six months ended June 30, 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 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 are potentially 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.

Oil and Natural Gas Properties

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.

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.

Income Taxes

Income Taxes

Vanguard was 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 June 30, 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.

New Pronouncements Recently Adopted

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. 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 expected credit losses on 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 incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. In May 2019, the FASB updated Topic 326 by issuing ASU 2019-05, Financial Instruments-Credit Losses (Topic 326): Targeted Transition Relief, which provides entities that have certain instruments within the scope of Subtopic 326-20, Financial Instruments-Credit Losses - Measured at Amortized Cost, with an option to irrevocably elect the fair value option in Subtopic 825-10, Financial Instruments-Overall, applied on an instrument-by-instrument basis for eligible instruments, upon adoption of Topic 326. The amendments in these Updates will be applied using a modified-retrospective approach and, for public entities, are effective for fiscal 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.

Use of Estimates

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

Revenue Recognition

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.

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 six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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Chapter 11 Proceedings (Tables)

6 Months Ended

Jun. 30, 2019

Reorganizations [Abstract]

Schedule of Liabilities Subject to compromise

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

Schedule of Reorganization Items

The following table summarizes the components included in reorganization items on our consolidated statements of operations for the three and six months ended June 30, 2019 and 2018:

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

(1) Includes $14.1 million of accrued reorganization costs as of June 30, 2019 representing unpaid professional and legal fees directly related to the Chapter 11 Cases. Total payments made for professional and legal fees related to the 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 VNG Notes as these debt instruments were expected to be impacted by the bankruptcy reorganization process.

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Debt (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Schedule of Financing Arrangements

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

Description	Interest Rate	Maturity Date	June 30, 2019			December 31, 2018
VNG Revolving Loan	Variable (1)	February 1, 2021	$	677,718		$	682,145
Term Loan	Variable (2)	May 1, 2021	123,438			123,438
New Money Facility	Variable (3)		20,000			—
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			$	901,878		$	889,635
Less:
Liabilities subject to compromise (Note 2)			(881,878		)	—
Short-term debt			(20,000		)	—
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 6.27% at December 31, 2018. In accordance with ASC 852, Reorganizations, we have accrued interest expense only up to the Petition Date.

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

(3) Variable interest rate of 7.92% at June 30, 2019. Borrowings under the New Money Facility were paid off prior to maturity on July 16, 2019 in connection with Grizzly’s emergence from the Chapter 11 Cases.

(4) Under ASU No. 2016-02, the lease financing obligations are classified and presented under the “Lease Liabilities” line item in the Balance Sheet. See Note 9, “Leases,” for a detailed discussion of 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.

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Price Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivatives Outstanding

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 period indicated (in thousands):

	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	)

Schedule of Changes in Fair Value of Commodity and Interest Rate Derivatives

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

	Six Months Ended June 30, 2019			Year Ended December 31, 2018
Derivative asset (liability) at beginning of period, net	$	6,570		$	(64,437	)
Net losses on commodity derivative contracts	(70,202		)	(9,259		)
Cash settlements paid on matured commodity derivative contracts	9,762			80,266
Termination of commodity derivative contracts	53,870			—
Derivative asset at end of period, net	$	—		$	6,570

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Schedule of Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis

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

	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	)

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation [Abstract]

Schedule of Changes in 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	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

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Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Leases

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

	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

The components of lease expense for the three and six months ended June 30, 2019 were as follows (in thousands):

		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

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

Supplemental balance sheet information related to leases as of June 30, 2019 was as follows:

Leases (in thousands)	Classification	June 30, 2019
Assets
Operating lease assets	Lease assets	$	5,699
Finance lease assets, at cost	Lease assets	10,636
Accumulated amortization	Lease assets	(2,674		)
Finance lease assets, net	Lease assets	7,962
Total lease assets		$	13,661
Liabilities
Current
Operating	Liabilities subject to compromise	$	1,116
Finance	Liabilities subject to compromise	5,183
Long-Term
Operating	Liabilities subject to compromise	5,051
Finance	Liabilities subject to compromise	2,969
Total lease liabilities		$	14,319

Finance Lease Maturity

The maturity of our lease liabilities as of June 30, 2019 were 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

Operating Lease Maturity

The maturity of our lease liabilities as of June 30, 2019 were 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

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Please see Note 9, “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

Schedule of Future Minimum Transportation Demand Charges

The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of June 30, 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.

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

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2019

Share-based Payment Arrangement [Abstract]

Schedule of Nonvested Restricted Stock Units Activity

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

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General (Details)	6 Months Ended
	Jun. 30, 2019 operating_area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating areas	9

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Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Lease assets	$ 13,661
Lease liability	$ 14,319
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Lease assets		$ 17,500
Lease liability		$ 18,000
Potato Hills Gas Gathering System
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Ownership percentage	51.00%

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Chapter 11 Proceedings (Creditors’ Committees - Appointment & Formation and Schedules and Statements - Claims & Claims Resolution Process) (Details) $ in Billions	Aug. 14, 2019 USD ($) claimant claim	Apr. 11, 2019 member
Subsequent Event [Line Items]
Number of members on committee | member		3
Subsequent Event
Subsequent Event [Line Items]
Number claims filed | claim	1,405
Amount of claims filed | $	$ 7.7
Number of claimants | claimant	1,206

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Chapter 11 Proceedings (Plan Support Agreement) (Details)	Jul. 03, 2019	May 08, 2019
Revolving Credit Facility
Subsequent Event [Line Items]
Percentage of debt		66.66%
Percentage of number of loans included		50.10%
Line of Credit | Secured Swap Debt
Subsequent Event [Line Items]
Percentage of debt		66.66%
Percentage of number of loans included		50.10%
Term Loan | Term Loan
Subsequent Event [Line Items]
Percentage of debt		66.66%
Percentage of number of loans included		50.10%
Term Loan | Second Lien Notes | Subsequent Event
Subsequent Event [Line Items]
Percentage of debt	66.66%

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Chapter 11 Proceedings (Debtor-in-Possession Financing) (Details) - Debtor-in-Possession Financing - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jul. 12, 2019	Apr. 04, 2019
Debt Instrument [Line Items]
Commitment fee (percent)	1.00%
LIBOR
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	5.50%
Base Rate
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	4.50%
New Money Facility
Debt Instrument [Line Items]
Aggregate debt	$ 65.0
Amount drawn			$ 20.0
New Money Facility | Subsequent Event
Debt Instrument [Line Items]
Amount drawn		$ 5.0
Rollup Facility
Debt Instrument [Line Items]
Aggregate debt	$ 65.0

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Chapter 11 Proceedings (Plan of Reorganization) (Details) - member	Jul. 09, 2019	Jun. 30, 2019
Class of Stock [Line Items]
Number of members on board of managers		5
Subsequent Event
Class of Stock [Line Items]
Percent of face amount, unpaid claim	2.00%
Term Loan B | Term Loan | Series C Preferred Units | Subsequent Event
Class of Stock [Line Items]
Percentage of pro-rata share	75.00%
VNG Credit Facility | Line of Credit | Series C Preferred Units | Subsequent Event
Class of Stock [Line Items]
Percentage of pro-rata share	10.00%
VNG Notes | Senior Notes | Common Class C | Subsequent Event
Class of Stock [Line Items]
Percentage of pro-rata share	15.00%

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Chapter 11 Proceedings (Preferred and Common Units) (Details)	Jun. 30, 2019 vote $ / shares
Class of Stock [Line Items]
Liquidation preference (USD per unit) | $ / shares	$ 10
Number of votes for each outstanding unit | vote	1
Series A Preferred Stock
Class of Stock [Line Items]
Basis spread on variable rate	9.50%
Series B Preferred Stock
Class of Stock [Line Items]
Basis spread on variable rate	10.50%

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Chapter 11 Proceedings (Exit Facility) (Details) - Subsequent Event - USD ($)	Jul. 16, 2019	Jul. 15, 2019
Exit Facility
Debt Instrument [Line Items]
Guarantor percentage	95.00%
Line of Credit | Revolving Loans
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 65,000,000.0	$ 65,000,000.0
Line of Credit | Revolving Loans | Base Rate | Minimum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	2.00%
Line of Credit | Revolving Loans | Base Rate | Maximum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	3.00%
Line of Credit | Revolving Loans | Eurodollar | Minimum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	3.00%
Line of Credit | Revolving Loans | Eurodollar | Maximum
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	4.00%
Line of Credit | Term Loan A
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 65,000,000.0
Interest rate at period end	1.00%
Line of Credit | Term Loan A | Base Rate
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	3.00%
Line of Credit | Term Loan A | Eurodollar
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	4.00%
Line of Credit | RBL Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 65,000,000.0
Commitment fee (percent)	0.50%
Maximum consolidated first-out leverage ratio	2.50
Minimum current ratio	1.00
Minimum coverage ratio	1.00
Term Loan | Term Loan B
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 285,000,000.0	$ 285,000,000.0
Term Loan | Term Loan B | Base Rate
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	6.50%
Term Loan | Term Loan B | Eurodollar
Debt Instrument [Line Items]
Applicable margin on variable rate (percent)	7.50%

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Chapter 11 Proceedings (Amended and Restated Employment Agreements) (Details) - Subsequent Event $ in Thousands	Jul. 16, 2019 USD ($)
Sloan Employment Agreement
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Renew period	1 year
Annual base salary	$ 720
Target bonus, percent of base salary	100.00%
Target quarterly bonus, amount	$ 180
Quarterly target bonus, percentage	150.00%
Voluntary resignation period	30 days
Anniversary of Effective Date	3 months
Midgett Employment Agreement
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Renew period	1 year
Annual base salary	$ 325
Target bonus, percent of base salary	80.00%
Target quarterly bonus, amount	$ 65
Quarterly target bonus, percentage	150.00%
Voluntary resignation period	30 days
Anniversary of Effective Date	3 months
Curth Employment Agreement
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Renew period	1 year
Annual base salary	$ 380
Target bonus, percent of base salary	80.00%
Target quarterly bonus, amount	$ 76
Quarterly target bonus, percentage	150.00%
Voluntary resignation period	30 days
Anniversary of Effective Date	3 months

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Chapter 11 Proceedings (Acceleration of Debt) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Aug. 01, 2017
Interest expense	$ 11,600
VNG Revolving Loan | Line of Credit
Debt amount outstanding	677,718	$ 682,145
Term Loan | Term Loan
Debt amount outstanding	$ 123,438	$ 123,438	$ 125,000

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Chapter 11 Proceedings (Liabilities Subject to Compromise) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Reorganizations [Abstract]
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	$ 0

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Chapter 11 Proceedings (Interest Expense) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Reorganizations [Abstract]
Interest Expense	$ 15.7	$ 15.7

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Chapter 11 Proceedings (Reorganization Items) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Reorganizations [Abstract]
Professional and legal fees	$ 24,743	$ 610	$ 36,820	$ 2,317
Deferred financing costs and debt discount	0	0	6,311	0
Total Reorganization items	24,743	$ 610	43,131	$ 2,317
Accrued reorganization costs	14,100		14,100
Total payments made for professional and legal fees related to Chapter 11 Cases			22,700
Unamortized debt issuance costs and debt discounts	$ 6,300		$ 6,300

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Revenues (Details)	Jun. 30, 2019
Minimum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation period	30 days
Maximum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation period	90 days
Transportation, gathering, processing and compression
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation period	1 year

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Divestitures (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Mar. 31, 2019	Jun. 30, 2019
Business Combinations [Abstract]
Proceeds from divestiture	$ 4.4
Transaction costs		$ 0.2

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Debt (Financing Arrangements) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Aug. 01, 2017
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 0	$ (7,124)
Total debt	901,878	889,635
Liabilities subject to compromise	(881,878)	0
Short-term debt	(20,000)	0
Long-term debt classified as current	0	(879,181)
Current portion of Lease Financing Obligation		(5,008)
Total long-term debt	$ 0	5,446
Lease Financing Obligations
Debt Instrument [Line Items]
Stated interest rate (percent)	4.16%
Maturity Date	Aug. 10, 2020
Debt amount outstanding	$ 0	$ 10,454
VNG Revolving Loan | Line of Credit
Debt Instrument [Line Items]
Variable interest rate (percent)		6.27%
Maturity Date	Feb. 01, 2021
Debt amount outstanding	$ 677,718	$ 682,145
Term Loan | Term Loan
Debt Instrument [Line Items]
Variable interest rate (percent)		9.96%
Maturity Date	May 01, 2021
Debt amount outstanding	$ 123,438	$ 123,438	$ 125,000
New Money Facility
Debt Instrument [Line Items]
Variable interest rate (percent)	7.92%
Debt amount outstanding	$ 20,000	0
VNG Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (percent)	9.00%
Maturity Date	Feb. 15, 2024
Debt amount outstanding	$ 80,722	$ 80,722

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Debt (Acceleration of Debt Obligations) (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Debt Disclosure [Abstract]
Debt issuance costs		$ 6.3
Accrued liabilities	$ 12.5	12.5
Interest Expense	$ 15.7	$ 15.7

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Debt (VNG Credit Facility) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Aug. 01, 2017
VNG Revolving Loan
Debt Instrument [Line Items]
Current borrowing capacity	$ 677,900		$ 850,000
Term Loan | Term Loan
Debt Instrument [Line Items]
Debt amount outstanding	$ 123,438	$ 123,438	$ 125,000

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Debt (VNG Notes) (Details) - VNG Notes - Senior Notes $ in Millions	Aug. 01, 2017 USD ($)
Debt Instrument [Line Items]
Debt amount outstanding	$ 80.7
Stated interest rate (percent)	9.00%

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Debt (Exit Facility) (Details) - Subsequent Event - USD ($)	Jul. 16, 2019	Jul. 15, 2019
Line of Credit | Revolving Loans
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 65,000,000.0	$ 65,000,000.0
Term Loan | Term Loan B
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 285,000,000.0	$ 285,000,000.0

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Price Risk Management Activities (Narrative) (Details) - USD ($) $ in Thousands	Apr. 01, 2019	Dec. 31, 2018
Derivative [Line Items]
Gross Amounts of Recognized Assets		$ 22,361
Commodity Contract
Derivative [Line Items]
Estimate of possible loss due to counterparty failure to perform, maximum	$ 53,900
Gross Amounts of Recognized Assets		$ 22,361

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Price Risk Management Activities (Balance Sheet Presentation) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	$ 22,361
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(9,308)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	13,053
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(15,791)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	9,308
Net Amounts Presented in the Condensed Consolidated Balance Sheets(1)	(6,483)
Commodity Contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	22,361
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(9,308)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	13,053
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(15,791)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	9,308
Net Amounts Presented in the Condensed Consolidated Balance Sheets(1)	$ (6,483)

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Price Risk Management Activities (Change in Fair Value of Derivatives) (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]
Derivative asset (liability) at beginning of period, net	$ 6,570	$ (64,437)	$ (64,437)
Net losses on commodity derivative contracts	(70,202)		(9,259)
Cash settlements paid on matured commodity derivative contracts	9,762	$ 27,139	80,266
Termination of commodity derivative contracts	53,870		0
Derivative asset at end of period, net	$ 0		$ 6,570

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Fair Value Measurements (Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - Fair Value Measured on a Recurring Basis $ in Thousands	Dec. 31, 2018 USD ($)
Derivative Asset [Abstract]
Commodity price derivative contracts	$ 13,053
Total derivative instruments	13,053
Liabilities:
Commodity price derivative contracts	(6,483)
Total derivative instruments	(6,483)
Fair Value Measurements Using Level 2
Derivative Asset [Abstract]
Commodity price derivative contracts	13,053
Total derivative instruments	13,053
Liabilities:
Commodity price derivative contracts	(6,483)
Total derivative instruments	$ (6,483)

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Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 323,188	$ 7,552	$ 323,626	$ 22,153
Properties Subject to Impairment Review | Fair Value Measurements Using Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and natural gas properties, net cost basis	546,200	89,100	546,200	89,100
Oil and natural gas properties, fair value	$ 222,600	$ 66,900	$ 222,600	$ 66,900

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Roll-forward of asset retirement obligations:
Asset retirement obligation, beginning balance	$ 143,208	$ 157,424
Liabilities added during the current period	65	610
Accretion expense	4,377	9,295
Liabilities related to assets divested	(294)	(16,687)
Retirements	(1,563)	(2,499)
Change in estimate	(22)	(4,935)
Asset retirement obligation, ending balance	145,771	143,208
Less: current obligations	(4,752)
Long-term asset retirement obligation	$ 141,019	$ 139,433
Future inflation factor	1.60%	1.70%
Minimum
Roll-forward of asset retirement obligations:
Credit-adjusted risk-free interest rate	6.30%	6.50%
Maximum
Roll-forward of asset retirement obligations:
Credit-adjusted risk-free interest rate	6.80%	7.10%

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Leases (Lease Expense) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Short-term lease cost	$ 371	$ 666
Operating lease cost	670	1,521
Amortization of lease assets	1,341	2,674
Interest on lease liabilities	125	262
Net lease cost	$ 2,507	$ 5,123
Minimum
Lessee, Lease, Description [Line Items]
Renewal term		1 year
Maximum
Lessee, Lease, Description [Line Items]
Renewal term		10 years

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Leases (Lease Terms and Discount Rates) (Details)	Jun. 30, 2019
Leases [Abstract]
Weighted-average remaining lease term, Operating leases	5 years 9 months 27 days
Weighted-average remaining lease term, Finance leases	1 year 7 months 9 days
Weighted-average discount rate, Operating leases	18.50%
Weighted-average discount rate, Finance leases	5.70%

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Leases (Supplemental Balance Sheet Information) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Leases [Abstract]
Operating lease assets	$ 5,699
Finance lease assets, at cost	10,636
Accumulated amortization	(2,674)
Finance lease assets, net	7,962
Total lease assets	13,661
Operating, current	1,116
Finance, current	5,183
Operating, long-term	5,051
Finance, long-term	2,969
Total lease liabilities	$ 14,319

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Leases (Maturity) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Operating Leases
2019 (remaining of year)	$ 1,221
2020	1,763
2021	1,557
2022	1,255
2023	1,247
Thereafter	3,150
Total undiscounted lease liability	10,193
Imputed interest	(4,026)
Total discounted liability	6,167
Finance Leases
2019 (remaining of year)	2,755
2020	4,427
2021	1,347
2022	55
2023	0
Thereafter	0
Total undiscounted lease liability	8,584
Imputed interest	(432)
Total discounted liability	8,152
Total
2019 (remaining of year)	3,976
2020	6,190
2021	2,904
2022	1,310
2023	1,247
Thereafter	3,150
Total undiscounted lease liability	18,777
Imputed interest	(4,458)
Total discounted liability	$ 14,319

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Leases (Supplemental Cash Flow) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Leases [Abstract]
Operating cash flows from operating leases		$ 1,870
Operating cash flows from finance leases		262
Financing cash flows from finance leases		$ 2,484
Rent expense	$ 600		$ 1,100

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Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Other Commitments [Line Items]
Lease commitments		$ 9,236
Remaining term of contracts	1 year
Estimated commitments to third-party operators under joint operating agreements, due in the next 12 months	$ 9,600
Pinedale Field Drilling And Green RIver Basin
Other Commitments [Line Items]
Estimated commitments to third-party operators under joint operating agreements, due in the next 12 months	2,500
Cotton Valley Gas Plant in Gulf Coast
Other Commitments [Line Items]
Estimated commitments to third-party operators under joint operating agreements, due in the next 12 months	$ 6,100

XML

Commitments and Contingencies (Lease Commitments) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 1,211
2020	1,149
2021	1,169
2022	1,204
2023	1,241
Thereafter	3,262
Total	$ 9,236

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Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Gross future minimum transportation demand
July 1, 2019 - December 31, 2019	$ 410
Due 2020	410
Total	$ 820

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Stockholders’ Equity (Deficit) (Earning Per Share) (Details) - shares	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Restricted Stock Units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	301,065	143,181
Warrant
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	1,300,000	1,300,000

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Share-Based Compensation (MIP Restricted Stock) (Details) - Restricted Stock Units (RSUs)	6 Months Ended
	Jun. 30, 2019 $ / shares shares
Time-Based Restricted Stock Units
Non-vested units at beginning of period (in units) | shares	244,496
Vested (in units) | shares	(1,473)
Non-vested units at end of period (in units) | shares	243,023
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit) | $ / shares	$ 16.62
Vested (in dollars per unit) | $ / shares	11.99
Non-vested units at end of period (in dollars per unit) | $ / shares	$ 16.65

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Share-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 0.6	$ 0.6	$ 1.2	$ 1.1
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	2.7		$ 2.7
Unrecognized compensation cost recognition period (in years)			1 year 6 months
TSR Performance RSU Replacement Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 0.8		$ 0.8
Unrecognized compensation cost recognition period (in years)			1 year 6 months

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Related Parties (Details) - Professional fees $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
RPA
Related Party Transaction [Line Items]
Professional fees	$ 2.2
Accrued professional services expense	0.5
A&M Entity
Related Party Transaction [Line Items]
Professional fees	$ 0.2