Vanguard Natural Resources, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	vnr2017q310-qexhibit32x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	vnr2017q310-qexhibit32x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	vnr2017q310-qexhibit31x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	vnr2017q310-qexhibit31x1.htm
EX-10.13 - EXHIBIT 10.13 - Vanguard Natural Resources, Inc.	ex1013-mip.htm

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 September 30, 2017
	OR
	o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-33756

Vanguard Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)



Delaware		80-0411494
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)



5847 San Felipe, Suite 3000 Houston, Texas		77057
(Address of Principal Executive Offices)		(Zip Code)

(832) 327-2255

(Registrant’s Telephone Number, Including Area Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). ☑ Yes o No

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



o	Large accelerated filer	o	Accelerated filer
o	Non-accelerated filer	☑	Smaller reporting company
	(Do not check if a 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

As of November 7, 2017, the registrant had 20,055,958 outstanding shares of common stock, $0.001 par value

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS



		Page

PART I – FINANCIAL INFORMATION
Item 1.	Unaudited Consolidated Financial Statements
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	5
	Consolidated Statements of Equity	6
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	62

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 3.	Defaults Upon Senior Securities	64
Item 4.	Mine Safety Disclosures	64
Item 5.	Other Information	64
Item 6.	Exhibits	64

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 equivalent

MBOE	= thousand barrels of oil equivalent	NGLs	= natural gas liquids

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

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

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

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

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q 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 on Form 10-Q 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. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements. 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 statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. 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, 2016 (the “2016 Annual Report”), and this Quarterly Report on Form 10-Q, and those set forth from time to time in our filings with the Securities and Exchange Commission (the “SEC”), which are available on our website at www.vnrenergy.com and through the SEC’s Electronic Data Gathering and Retrieval System at www.sec.gov. These factors and risks include, but are not limited to:


•	our ability to achieve the anticipated benefits from the consummation of the cases filed under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”);


•	our ability to execute our business strategies, including our business strategies post-emergence from the Chapter 11 Cases (as defined below);


•	ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing and following emergence from the Chapter 11 Cases;


•	our ability to obtain sufficient financing to execute our business plan post-emergence;


•	our ability to meet our liquidity needs;


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


•	increased advisory costs to implement the reorganization;


•	the impact of the Chapter 11 restructuring on the liquidity and market price of our common stock and on our ability to access the public capital markets;


•	risks relating to any of our unforeseen liabilities;


•	further 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 commodity 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 comply with restrictive covenants contained in the agreements governing our indebtedness that may adversely affect operational flexibility;


•	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 exploitation and development operations and acquisitions;


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


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


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


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


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


•	ability to replace oil and natural gas reserves;


•	any loss of senior management or technical personnel;


•	competition in the oil and natural gas industry;


•	risks arising out of hedging transactions;


•	the costs and effects of litigation;


•	sabotage, terrorism or other malicious intentional acts (including cyber attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance; and


•	costs of tax treatment as a corporation.

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

PART I – FINANCIAL INFORMATION

Item 1. Unaudited Consolidated Financial Statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)



	Successor			Predecessor
	Two Months			One Month			Three Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Revenues:
Oil sales	$	27,303		$	11,820		$	41,999
Natural gas sales	39,032			4,412			52,454
NGLs sales	13,465			4,792			10,733
Oil, natural gas and NGLs sales	79,800			21,024			105,186
Net gains (losses) on commodity derivative contracts	(32,352		)	(12,019		)	21,099
Total revenues	47,448			9,005			126,285
Costs and expenses:
Production:
Lease operating expenses	26,447			11,787			39,386
Transportation, gathering, processing and compression	8,044			—			—
Production and other taxes	5,737			1,983			11,823
Depreciation, depletion, amortization, and accretion	27,578			7,328			32,096
Impairment of goodwill	—			—			252,676
Exploration expense	105			—			—
Selling, general and administrative expenses	7,194			8,738			11,454
Total costs and expenses	75,105			29,836			347,435
Loss from operations	(27,657		)	(20,831		)	(221,150		)
Other income (expense):
Interest expense	(9,615		)	(5,003		)	(22,976		)
Net gains on interest rate derivative contracts	—			—			764
Net loss on acquisition of oil and natural gas properties	—			—			(2,117		)
Other	36			472			111
Total other expense, net	(9,579		)	(4,531		)	(24,218		)
Loss before reorganization items	(37,236		)	(25,362		)	(245,368		)
Reorganization items (Note 3)	—			988,452			—
Net income (loss)	$	(37,236	)	$	963,090		$	(245,368	)
Less: Net income attributable to non-controlling interests	(61		)	(1		)	(27		)
Net income (loss) attributable to Vanguard stockholders/unitholders	(37,297		)	963,089			(245,395		)
Distributions to Preferred unitholders	—			—			(6,690		)
Net income (loss) attributable to Common stockholders/Common and Class B unitholders	$	(37,297	)	$	963,089		$	(252,085	)
Net income (loss) per share/unit – basic and diluted	$	(1.86	)	$	7.33		$	(1.92	)
Weighted average Common shares/units outstanding
Common shares/units – basic and diluted	20,056			130,978			131,040
Predecessor Class B units – basic and diluted	—			420			420

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Revenues:
Oil sales	$	27,303		$	97,496		$	127,594
Natural gas sales	39,032			113,587			121,756
NGLs sales	13,465			35,565			30,752
Oil, natural gas and NGLs sales	79,800			246,648			280,102
Net losses on commodity derivative contracts	(32,352		)	(24,887		)	(15,752		)
Total revenues	47,448			221,761			264,350
Costs and expenses:
Production:
Lease operating expenses	26,447			87,092			120,228
Transportation, gathering, processing and compression	8,044			—			—
Production and other taxes	5,737			21,186			29,967
Depreciation, depletion, amortization, and accretion	27,578			58,384			118,935
Impairment of oil and natural gas properties	—			—			365,658
Impairment of goodwill	—			—			252,676
Exploration expense	105			—			—
Selling, general and administrative expenses	7,194			28,810			35,884
Total costs and expenses	75,105			195,472			923,348
Income (loss) from operations	(27,657		)	26,289			(658,998		)
Other income (expense):
Interest expense	(9,615		)	(35,276		)	(72,612		)
Net gains (losses) on interest rate derivative contracts	—			30			(6,061		)
Net loss on acquisition of oil and natural gas properties	—			—			(3,782		)
Gain on extinguishment of debt	—			—			89,714
Other	36			783			363
Total other income (expense), net	(9,579		)	(34,463		)	7,622
Loss before reorganization items	(37,236		)	(8,174		)	(651,376		)
Reorganization items (Note 3)	—			908,485			—
Net income (loss)	$	(37,236	)	$	900,311		$	(651,376	)
Less: Net income attributable to non-controlling interests	(61		)	(13		)	(91		)
Net income (loss) attributable to Vanguard stockholders/unitholders	(37,297		)	900,298			(651,467		)
Distributions to Preferred unitholders	—			(2,230		)	(20,069		)
Net income (loss) attributable to Common stockholders/Common and Class B unitholders	$	(37,297	)	$	898,068		$	(671,536	)
Net income (loss) per share/unit – basic and diluted	$	(1.86	)	$	6.84		$	(5.12	)
Weighted average Common shares/units outstanding
Common shares/units – basic and diluted	20,056			130,962			130,862
Predecessor Class B units – basic and diluted	—			420			420

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(Unaudited)



	Successor			Predecessor
	September 30, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	16,765		$	49,957
Trade accounts receivable, net	56,265			97,138
Derivative assets	254			—
Restricted cash	28,455			—
Other current assets	4,709			7,944
Total current assets	106,448			155,039
Oil and natural gas properties
Proved properties	1,535,917			4,725,692
Unproved properties	95,611			—
	1,631,528			4,725,692
Accumulated depletion, amortization and impairment	(25,905		)	(3,867,439		)
Oil and natural gas properties, net – successful efforts method at September 30, 2017 and full cost method at December 31, 2016	1,605,623			858,253
Other assets
Goodwill	—			253,370
Other assets	24,476			42,626
Total assets	$	1,736,547		$	1,309,288

Liabilities and equity (deficit)
Current liabilities
Accounts payable:
Trade	$	12,889		$	12,929
Affiliates	—			1,443
Accrued liabilities:
Lease operating	12,346			14,909
Developmental capital	12,596			6,676
Interest	4,973			13,345
Production and other taxes	25,314			32,663
Other	23,818			5,416
Derivative liabilities	29,506			125
Oil and natural gas revenue payable	27,120			33,672
Long-term debt classified as current (Note 5)	—			1,753,345
Other current liabilities	11,757			14,160
Total current liabilities	160,319			1,888,683
Long-term debt, net of current portion (Note 5)	938,224			15,475
Derivative liabilities	25,669			—
Asset retirement obligations, net of current portion	140,079			264,552
Other long-term liabilities	403			39,443
Total liabilities	1,264,694			2,208,153
Commitments and contingencies (Note 9)

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - Continued

(in thousands, except unit data)

(Unaudited)



	Successor			Predecessor
	September 30, 2017			December 31, 2016
Stockholders’ equity/Members’ (deficit) (Note 10)
Predecessor Preferred units, no units issued or outstanding at September 30, 2017; 13,881,873 units issued and outstanding at December 31, 2016	—			335,444
Predecessor Common units, no units issued or outstanding at September 30, 2017; 131,008,670 units issued and outstanding at December 31, 2016	—			(1,248,767		)
Predecessor Class B units, no units issued or outstanding at September 30, 2017; 420,000 issued and outstanding at December 31, 2016	—			7,615
Successor common stock ($0.001 par value, 50,000,000 shares authorized and 20,055,694 shares issued and outstanding at September 30, 2017; no shares authorized or issued at December 31, 2016	20			—
Successor additional paid-in capital	506,923			—
Successor accumulated deficit	(37,297		)	—
Total stockholders' equity/members’ (deficit)	469,646			(905,708		)
Non-controlling interest in subsidiary	2,207			6,843
Total stockholders' equity/members’ (deficit)	471,853			(898,865		)
Total liabilities and equity (deficit)	$	1,736,547		$	1,309,288

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT (PREDECESSOR)

FOR THE SEVEN MONTH PERIOD ENDED JULY 31, 2017 AND THE YEAR ENDED DECEMBER 31, 2016

(in thousands)

(Unaudited)



	Cumulative Preferred Units			Common Units			Class B Units			Non-controlling Interest			Total Members’ Deficit
Balance at January 1, 2016 (Predecessor)	$	335,444		$	(430,494	)	$	7,615		$	—		$	(87,435	)
Issuance costs related to prior period equity transactions	—			(250		)	—			—			(250		)
Distributions to Preferred unitholders (see Note 9)	—			(5,575		)	—			—			(5,575		)
Distributions to Common and Class B unitholders (see Note 9)	—			(7,998		)	—			—			(7,998		)
Unit-based compensation	—			10,639			—			—			10,639
Non-controlling interest in subsidiary	—			—			—			7,452			7,452
Net income (loss)	—			(815,089		)	—			82			(815,007		)
Potato Hills cash distribution to non-controlling interest	—			—			—			(691		)	(691		)
Balance at December 31, 2016 (Predecessor)	$	335,444		$	(1,248,767	)	$	7,615		$	6,843		$	(898,865	)
Issuance costs related to prior period equity transactions	—			19			—			—			19
Unit-based compensation	—			5,391			—			—			5,391
Net income	—			900,298			—			13			900,311
Potato Hills cash distribution to non-controlling interest	—			—			—			(235		)	(235		)
Balance at July 31, 2017 (Predecessor)	$	335,444		$	(343,059	)	$	7,615		$	6,621		$	6,621
Cancellation of Predecessor equity	(335,444		)	343,059			(7,615		)	(4,347		)	(4,347		)
Balance at July 31, 2017 (Predecessor)	$	—		$	—		$	—		$	2,274		$	2,274

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (SUCCESSOR)

FOR THE TWO MONTH PERIOD ENDED SEPTEMBER 30, 2017

(in thousands)

(Unaudited)



	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Non- controlling Interest			Total Stockholders' Equity
Issuance of Successor common stock and warrants	$	20	$	506,923	$	—		$	—		$	506,943
Balance at July 31, 2017 (Successor)	20		506,923		—			2,274			509,217
Net income (loss)	—		—		(37,297		)	61			(37,236		)
Potato Hills cash distribution to non-controlling interest	—		—		—			(128		)	(128		)
Balance at September 30, 2017 (Successor)	$	20	$	506,923	$	(37,297	)	$	2,207		$	471,853

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
(in thousands)	September 30, 2017			July 31, 2017			September 30, 2016
Operating activities
Net income (loss)	$	(37,236	)	$	900,311		$	(651,376	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	27,578			58,384			118,935
Impairment of oil and natural gas properties	—			—			365,658
Impairment of goodwill	—			—			252,676
Amortization of deferred financing costs	443			2,584			3,306
Amortization of debt discount	—			348			2,739
Reorganization cost	—			(937,956		)	—
Compensation related items	—			5,429			8,850
Net losses on commodity and interest rate derivative contracts	32,352			24,858			21,813
Cash settlements received on matured commodity derivative contracts	(2,326		)	7			198,104
Cash settlements paid on matured interest rate derivative contracts	—			(95		)	(6,770		)
Net loss on acquisition of oil and natural gas properties	—			—			3,782
Gain on extinguishment of debt	—			—			(89,714		)
Changes in operating assets and liabilities:
Trade accounts receivable	(398		)	34,845			10,482
Other current assets	(253		)	1,435			(553		)
Net premiums received (paid) on commodity derivative contracts	—			(16		)	176
Increase in restricted cash	—			(28,455		)	—
Accounts payable and oil and natural gas revenue payable	(6,692		)	19,444			(36,296		)
Payable to affiliates	—			(895		)	65
Accrued expenses and other current liabilities	(186		)	(27,018		)	(32,497		)
Other assets	446			(922		)	10,197
Net cash provided by operating activities	13,728			52,288			179,577
Investing activities
Additions to property and equipment	—			(102		)	(73		)
Potato Hills Gas Gathering System acquisition	—			—			(7,501		)
Additions to oil and natural gas properties	(14,431		)	(25,694		)	(49,117		)
Deposits and prepayments of oil and natural gas properties	—			(23,731		)	(12,257		)
Proceeds from the sale of oil and natural gas properties	(9,013		)	126,363			288,483
Net cash provided by (used in) investing activities	(23,444		)	76,836			219,535
Financing activities
Proceeds from long-term debt	—			—			93,500
Repayment of long-term debt	(835		)	(41,603		)	(430,897		)
Proceeds from Term Loan borrowings	—			125,000			—
Repayment of debt under the predecessor revolving credit facility	—			(500,266		)	—
Proceeds from rights offerings and second lien investment	—			275,000			—
Distributions to Preferred unitholders	—			—			(6,690		)
Distributions to Common and Class B unitholders	—			—			(11,917		)
Potato Hills distribution to non-controlling interest	(128		)	(235		)	(550		)
Financing fees	(166		)	(9,367		)	(3,764		)
Net cash used in financing activities	(1,129		)	(151,471		)	(360,318		)
Net increase (decrease) cash and cash equivalents	(10,845		)	(22,347		)	38,794
Cash and cash equivalents, beginning of period	27,610			49,957			—
Cash and cash equivalents, end of period	$	16,765		$	27,610		$	38,794



Supplemental cash flow information:
Cash paid for interest	$	4,196	$	29,631	$	60,575
Non-cash investing activity:
Asset retirement obligations, net	$	206	$	9,581	$	13,208

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

General

When referring to Vanguard Natural Resources, Inc. (formerly known as VNR Finance Corp. and also referred to as “Successor” or the “Company”), the intent is to refer to Vanguard Natural Resources, Inc. and its consolidated subsidiaries as a whole or an individual basis, depending on the context in which the statements are made. Vanguard Natural Resources, Inc. became the successor reporting company of Vanguard Natural Resources, LLC (“Old Vanguard”) pursuant to Rule 15d-5 of the Exchange Act on August 1, 2017 (the “Effective Date”). When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Old Vanguard, the predecessor that assigned all of its assets to the Successor pursuant to the Final Plan (as defined in Note 2) on the Effective Date, and its consolidated subsidiaries on a whole or on an individual basis, depending on the context in which the statements are made.

Description of the Business

We are an exploration and production company focused on the acquisition, production and development of oil and natural gas properties in the United States. Through our operating subsidiaries, as of September 30, 2017, we own properties and oil and natural gas reserves primarily located in ten operating areas:


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


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


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Big Horn Basin in Wyoming and Montana;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

Following the completion of the financial restructuring on August 1, 2017 (see Note 1, “Summary of Significant Accounting Policies, (b) Emergence from Voluntary Reorganization under Chapter 11” and Note 3, “Fresh-Start Accounting”), the Company had 20.1 million shares of its common stock outstanding. The Company’s shares of common stock and warrants are traded and quoted on the OTCQX market (which is operated by OTC Markets Group, Inc.) under the symbol VNRR.

1. Summary of Significant Accounting Policies

The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2016 from the audited financial statements contained in our 2016 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 on Form 10-Q along with our Predecessor’s 2016 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 September 30, 2017, 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 our Predecessor’s consolidated financial statements contained in our Predecessor’s 2016 Annual Report.


(a)	Basis of Presentation and Principles of Consolidation

The consolidated financial statements as of September 30, 2017 (Successor) and December 31, 2016 (Predecessor) and for the two months ended September 30, 2017 (Successor), the one and seven months ended July 31, 2017 (Predecessor), and the three and nine months ended September 30, 2016 (Predecessor) include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation.

We consolidate Potato Hills Gas Gathering System as we have 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 consolidated financial statements.


(b)	Emergence from Voluntary Reorganization under Chapter 11

On February 1, 2017 (the “Petition Date”), Old Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. On July 18, 2017, the Bankruptcy Court entered an order confirming the Final Plan (as defined in Note 2). The Company emerged from bankruptcy effective August 1, 2017. Please read Note 2. Emergence From Voluntary Reorganization Under Chapter 11 for a discussion of the Chapter 11 Cases and the Final Plan.

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

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


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

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

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

Because a new entity has been created at the Effective Date, and there is no comparability to the Predecessor’s financial statements (refer to Note 3, “Fresh-Start Accounting”), upon emergence from bankruptcy, we elected to adopt the Successful Efforts Method of Accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties in the Successor.

Under the successful efforts method, we will capitalize the costs of acquiring unproved and proved oil and natural gas leasehold acreage. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. Development costs are capitalized, including the costs of unsuccessful and successful development wells and the costs to drill and equip exploratory wells that find proved reserves. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization of the leasehold and development costs that are capitalized into proved oil and natural gas properties are computed using the units-of-production method, at the district level, based on total proved reserves and proved developed reserves, respectively. Upon sale or retirement of oil and gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized. Additionally, proved oil and natural gas properties are assessed for impairment in accordance with Accounting Standards Codification Topic 360 “Property, Plant and Equipment”, when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in 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.


(d)	Goodwill and Other Intangible Assets

Prior to July 31, 2017, we accounted for goodwill under the provisions of the Accounting Standards Codification (“ASC”) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represented the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill was not amortized, but was tested for impairment annually on October 1 or whenever indicators of impairment existed.


(e)	Income Taxes

Prior to July 31, 2017, the Company was a limited liability corporation treated as a partnership for federal and state income tax purposes, in which the taxable income tax or loss of the Company were passed through to its unitholders. Effective upon consummation of the Final Plan, the Successor became a C Corporation subject to federal and state income taxes. As a C corporation, we will account for income taxes, as required, under the liability method. Deferred tax assets and liabilities will be 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 will be 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 will be recognized in income in the period that includes the enactment date. Deferred tax assets will be 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.


(f)	New Pronouncements Recently Adopted

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five-step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP.

Throughout 2015 and 2016, the FASB issued a series of updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.

The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period with early adoption permitted for annual reporting periods beginning after December 15, 2016.

In conjunction with fresh-start accounting, the Company has elected to early adopt the standard effective August 1, 2017. We adopted using the modified retrospective method, which fresh-start accounting allows us to apply the new standard to all new contracts entered into on or after August 1, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of August 1, 2017. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 4, “Impact of ASC 606 Adoption,” for further details related to the Company’s adoption of this standard.


(g)	New Pronouncements Issued But Not Yet Adopted

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” (“ASU No. 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) 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. The ASU No. 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-48 “Statement of Cash Flows (Topic 230): Restricted Cash” which is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the consolidated balance sheets to cash, cash equivalents and restricted cash on the consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU No. 2017-01”). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as

a business combination. The ASU No. 2017-01 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and should be applied prospectively. The Company is currently evaluating the provisions of ASU 2017-01 and assessing the impact adoption may have on our consolidated financial statements. Currently, we do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in future periods.


(h)	Use of Estimates

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

2. Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

On February 1, 2017, the Predecessor and certain subsidiaries (such subsidiaries, together with the Predecessor, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.”

Prior to the filing of the Bankruptcy Petitions, on February 1, 2017, we entered into a restructuring support agreement (the “Initial RSA”). The Debtors entered into the Initial RSA with: (i) certain holders of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”), constituting at the time of signing approximately 52% of such holders (the “Consenting 2020 Noteholders”); (ii) certain holders of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and together with the Senior Notes due 2020, the “Senior Notes”), constituting at the time of signing approximately 10% of such holders (the “Consenting 2019 Noteholders” and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders”); and (iii) certain holders of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Old Second Lien Notes” or “Senior Notes due 2023”), constituting at the time of signing approximately 92% of such holders (the “Consenting Second Lien Noteholders”).

On June 6, 2017, certain lenders under the Predecessor’s Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Predecessor Credit Facility”), among them, Citibank, N.A., as administrative agent and Issuing Bank, (such lenders, the “Consenting RBL Lenders” and, together with the Consenting Senior Noteholders and Consenting Second Lien Noteholders, the “Restructuring Support Parties”), became parties to the amended Restructuring Support Agreement dated as of May 23, 2017.

On July 18, 2017, the Bankruptcy Court entered the Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Confirmation Order”), which approved and confirmed the Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Final Plan”). The Final Plan provided for the reorganization of the Debtors as a going concern and significantly reduced the long-term debt and annual interest payments of the Successor. During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017. The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Predecessor’s equity securities outstanding immediately before the Effective Date (including any unvested restricted units held by employees or officers of the Debtor, or options and warrants to purchase such securities) have been cancelled and are of no further force or effect as of the Effective Date. Under the Final Plan, the Debtors’ new organizational documents became effective on the Effective Date. The Successor’s new organizational documents authorize the Successor to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Final Plan on the Effective Date. In addition, on the Effective Date, the Successor entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Successor reserved for issuance 20.1 million outstanding shares of common stock, $0.001 par value. (“Common Stock”).

Plan of Reorganization

Upon emergence, pursuant to the terms of the Final Plan, the following significant transactions occurred:

•

The Predecessor transferred all of its membership interests in VNG, a Kentucky limited liability company and the Predecessor’s wholly owned first-tier subsidiary, to the Successor (formerly known as VNR Finance Corp.). VNG directly or indirectly owned all of the other subsidiaries of the Predecessor. As a result of the foregoing and certain other transactions, the Successor is no longer a subsidiary of the Predecessor and now owns all of the former subsidiaries of the Predecessor;

•

VNG, as borrower, entered into that certain Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loans”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date was $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million. The Successor Credit

Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). The holders of claims under the Predecessor Credit Facility received a full recovery, consisting of a cash pay down and their pro rata share of the Successor Credit Facility; The next borrowing base redetermination is scheduled for August of 2018;


•	The Successor issued approximately $80.7 million aggregate principal amount of new 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes” or “Senior Notes due 2024”) to certain eligible holders of their outstanding Old Second Lien Notes in full satisfaction of their claim of approximately $80.7 million related to the Old Second Lien Notes held by such holders;


•	The Predecessor’s Senior Notes were cancelled and the Consenting Senior Noteholders received their pro rata share of 3.38% (subject to dilution) of the Common Stock, in full and final satisfaction of their claims;


•	The Predecessor completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $275.0 million of gross proceeds. The rights offering resulted in the issuance of Common Stock, representing approximately 89.92% of outstanding shares of Common Stock, to holders of claims arising under the Senior Notes and to the Backstop Parties;

•

The Successor entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain recipients of shares of its Common Stock distributed on the Effective Date that were parties to the Amended and Restated Backstop Commitment Agreement (including the Backstop Parties and certain of their affiliates and related funds), in accordance with the terms set forth in the Final Plan (collectively, the “Registration Rights Holders”). Pursuant to the Registration Rights Agreement, we agreed to, among other things, file a registration statement with the SEC within 90 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined in the Registration Rights Agreement); We filed the registration statement on October 30, 2017;


•	Additional shares of Common Stock, representing eleven percent of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);


•	All outstanding Preferred Units (defined below) issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% of outstanding shares of Common Stock and (ii) Preferred Unit Warrants (as defined below), in full and final satisfaction of their interests;


•	All common equity of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders of the common equity received Common Unit Warrants (as defined below), in full and final satisfaction of their interests;

•

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

•

By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. Our current board of directors (the “Board”) consists of seven members, including our and our Predecessor’s Chief Executive Officer. Our Chief Financial Officer was initially appointed as a director upon emergence and became our Chief Financial Officer as well, following the resignation of our Predecessor’s Chief Financial Officer;


•	Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders; and


•	On the Effective Date, the Successor reserved for issuance 20,100,000 shares of Common Stock.

Each of the foregoing percentages of equity in the Successor were as of August 1, 2017 and are subject to dilution from the exercise of the Warrants described above, the MIP discussed further in Note 10, “Stockholders’ Equity (Members’ Deficit),” and other future issuances of equity interests.

See Note 5, “Debt,” and Note 10, “Stockholders’ Equity (Members’ Deficit),” for further information regarding the Predecessor and Successor’s debt and equity instruments.

Listing on the OTCQX Market

As a result of cancellation of the Predecessor’s units on the Effective Date, the units ceased to trade on the OTC Markets Group Inc.’s Pink marketplace. In September 2017, the Successor’s common stock was approved for trading on the OTCQX market under the symbol “VNRR.”

3. Fresh-Start Accounting

Upon the Company’s emergence from chapter 11 bankruptcy, the Company qualified for and applied fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value (as defined below) of the Company’s assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 2, “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” for the terms of the Final Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as “Successor” or “Successor Company.” However, the Company will continue to present financial information for any periods before application of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the fair value of the Successor Company’s total assets (the “Reorganization Value”) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization.

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company’s long-term debt and stockholders’ equity. The estimated Enterprise Value at the Effective Date was $1.425 billion as established in the Plan and approved by the bankruptcy court. The Enterprise Value was derived from an independent valuation using an asset based methodology of proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the Convenience Date.

The Company’s principal assets are its oil and natural gas properties. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five-year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $67.20 per barrel of oil, $3.69 per million British thermal units (MMBtu) of natural gas and $24.59 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees, quality differentials and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices.

In estimating the fair value of the Company's unproved acreage that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

See further discussion below under “Fresh-Start Adjustments” for the specific assumptions used in the valuation of the Company's various other assets.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of July 31, 2017 (in thousands):



	July 31, 2017
Enterprise Value	$	1,425,000
Plus: Cash and cash equivalents	27,610
Less: Debt	(943,392		)
Total stockholders' equity	509,217
Less: Fair value of warrants	(11,734		)
Less: Fair value of non-controlling interest	(2,274		)
Fair Value of Successor common stock	$	495,209

The following table reconciles the Company’s Debt as of July 31, 2017 (in thousands):



	July 31, 2017
Successor Credit Facility	$	730,000
Successor Term Loan	125,000
Senior Notes due 2024	80,722
Lease Financing Obligation, net of current portion	12,464
Current portion of Lease Financing Obligation	4,647
Total Fair value of debt	952,833
Successor Credit Facility fees and debt issuance costs	(9,441		)
Total Debt	$	943,392

The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of July 31, 2017 (in thousands):



	July 31, 2017
Enterprise Value	$	1,425,000
Plus: Cash and cash equivalents	27,610
Plus: Current liabilities, excluding current portion of Lease Financing Obligation	147,552
Plus: Other noncurrent liabilities	15,589
Plus: Long-term asset retirement obligation	136,769
Reorganization Value of Successor assets	$	1,752,520

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s unaudited condensed consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets and liabilities.



	As of July 31, 2017
(in thousands)	Predecessor			Reorganization Adjustments ⁽¹⁾				Fresh-Start Adjustments				Successor
Assets
Current assets
Cash and cash equivalents	$	68,933		$	(41,323	)	⁽²⁾	$	—			$	27,610
Trade accounts receivable, net	64,253			(155		)	⁽³⁾	(8,231		)	⁽¹⁵⁾	55,867
Derivative assets	3,236			—				—				3,236
Restricted cash	102,556			(74,101		)	⁽⁴⁾	—				28,455
Other current assets	4,430			(394		)	⁽⁵⁾	416			⁽¹⁶⁾	4,452
Total current assets	243,408			(115,973		)		(7,815		)		119,620
Oil and natural gas properties, at cost	4,635,867			—				(3,029,173		)	⁽¹⁷⁾	1,606,694
Accumulated depletion	(3,916,889		)	—				3,916,889			⁽¹⁷⁾	—
Oil and natural gas properties	718,978			—				887,716				1,606,694
Other assets
Goodwill	253,370			—				(253,370		)	⁽¹⁸⁾	—
Other assets	44,315			—				(18,109		)	^(19)(20)	26,206
Total assets	$	1,260,071		$	(115,973	)		$	608,422			$	1,752,520
Liabilities and equity (deficit)
Current liabilities
Accounts payable:
Trade	$	8,444		$	9,978		⁽⁶⁾	$	—			$	18,422
Accrued liabilities:
Lease operating	13,199			—				—				13,199
Development capital	8,928			—				—				8,928
Interest	8,478			(8,478		)	⁽⁷⁾	—				—
Production and other taxes	23,494			—				—				23,494
Other	20,933			12,297			⁽⁸⁾	—				33,230
Derivative liabilities	12,987			—				—				12,987
Oil and natural gas revenue payable	36,087			—				(7,808		)	⁽¹⁵⁾	28,279
Long-term debt classified as current	1,300,971			(1,300,971		)	⁽⁹⁾	—				—
Other	14,246			(382		)	⁽¹⁰⁾	(203		)	⁽²¹⁾	13,661
Total current liabilities	1,447,767			(1,287,556		)		(8,011		)		152,200
Long-term debt, net of current portion	12,647			926,281			⁽¹¹⁾	(183		)	⁽²²⁾	938,745
Derivative liabilities	15,143			—				—				15,143
Asset retirement obligations, net of current portion	260,089			—				(123,320		)	⁽²³⁾	136,769
Other long-term liabilities	37,683			—				(37,237		)	⁽²⁴⁾	446
Total liabilities not subject to compromise	1,773,329			(361,275		)		(168,751		)		1,243,303
Liabilities subject to compromise	479,911			(479,911		)	⁽¹²⁾	—				—
Total Liabilities	2,253,240			(841,186		)		(168,751		)		1,243,303



	As of July 31, 2017
	Predecessor			Reorganization Adjustments ⁽¹⁾				Fresh-Start Adjustments				Successor
Stockholders’ equity/Members’ (deficit) (Note 9)
Preferred units (Predecessor)	335,444			(335,444		)	⁽¹³⁾	—				—
Common units (Predecessor)	(1,342,849		)	763,217			⁽¹³⁾	579,632			⁽²⁵⁾	—
Class B units (Predecessor)	7,615			(7,615		)	⁽¹³⁾	—				—
Common stock (Successor)	—			20			⁽¹⁴⁾	—				20
Additional paid-in capital (Successor)	—			305,035			⁽¹⁴⁾	201,888			⁽²⁵⁾	506,923
Total VNR stockholders' equity/ members’ (deficit)	(999,790		)	725,213				781,520				506,943
Non-controlling interest in subsidiary	6,621			—				(4,347		)	⁽²⁶⁾	2,274
Total stockholders' equity/members’ (deficit)	(993,169		)	725,213				777,173				509,217
Total liabilities and equity (deficit)	$	1,260,071		$	(115,973	)		$	608,422			$	1,752,520

Reorganization Adjustments:

Represent amounts recorded as of the Convenience Date for the implementation of the Final Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s common stock and equity warrants, proceeds received from the Successor’s rights offering and issuance of the Successor’s debt.


2)	Changes in cash and cash equivalents included the following (in thousands):



Proceeds from equity investment from holders of Old Second Lien Notes	$	19,250
Proceeds from rights offering	255,750
Borrowings under the Successor's Term Loan	125,000
Removal of restriction on cash balance	102,556
Payment of holders of claims under the Predecessor Credit Facility	(500,266		)
Payment of interest and fees under the Predecessor Credit Facility	(3,390		)
Payment of Successor Credit Facility fees	(9,300		)
Payment of professional fees	(2,468		)
Funding of the general unsecured claims cash distribution pools	(6,750		)
Funding of the professional fees escrow account	(21,705		)
Changes in cash and cash equivalents	$	(41,323	)


3)	Reflects the write-off of lease incentive costs due to the rejection of the related lease contract.


4)	Net change to restricted cash includes the following:



Removal of restriction on cash balance	$	(102,556	)
Funding of the general unsecured claims cash distribution pools	6,750
Funding of the professional fees escrow account	21,705
	$	(74,101	)


5)	Primarily reflects the write-off of the Predecessor’s equity offering costs.


6)	Reflects reinstatement of payables for the general unsecured claims and trade claims cash distribution pool.


7)	Reflects payment of accrued interest related to Predecessor Credit Facility and Predecessor debtor-in-possession credit facility of $3.4 million and the capitalization of approximately $5.1 million accrued interest on the Old Second Lien Notes into the principal amount of the Senior Notes due 2024.


8)	Net increase in other accrued expenses reflect (in thousands):



Recognition of payables for the professional fees escrow account	$	12,627
Write-off of accrued non cash compensation related to Phantom Units granted	(330		)
Net increase in accounts payable and accrued expenses	$	12,297


9)	Reflects the repayment of outstanding borrowings under the Predecessor Credit Facility of approximately $500.3 million and the conversion of the remaining outstanding debt to Successor Credit Facility and the Senior Notes due 2024 to Long-Term Debt, net of the write-off of deferred financing fees.


10)	Reflects the write-off of deferred rent due to the rejection of the related lease contract.


11)	Reflects $855.0 million of outstanding borrowings under the Successor Credit Facility, which includes a $730.0 million revolving loan and a $125.0 million Term Loan. The adjustment also reflects the issuance of Senior Notes due 2024 of $80.7 million. The amounts are presented net of capitalized deferred financing fees related to each debt.


12)	Settlement of Liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):



Accounts payable and accrued expenses	$	36,224
Accrued interest payable	10,737
Debt	432,950
Total liabilities subject to compromise	479,911
Reinstatement of liability for the general unsecured claims	(4,978		)
Reinstatement of liability for settlement of an unsecured claim	(5,000		)
Issuance of common shares to holders of general unsecured claims	(1,089		)
Issuance of common shares to holders of Senior Notes claims	(16,715		)
Gain on settlement of liabilities subject to compromise	$	452,129


13)	Net change in Predecessor common units reflects (in thousands):



Recognition of gain on settlement of liabilities subject to compromise	$	452,129
Cancellation of Predecessor Preferred units	335,444
Cancellation of Predecessor Class B units	7,615
Write-off of deferred financing costs and debt discounts	(4,917		)
Recognition of professional and success fees	(14,968		)
Fair value of warrants issued to Predecessor unitholders	(11,734		)
Fair value of shares issued to Predecessor unitholders	(517		)
Terminated contracts	165
Net change in Predecessor Common units	$	763,217


14)	Net change in Successor equity reflects net increase in capital accounts as follows (in thousands):



Issuance of common stock to general unsecured creditors	$	1,089
Issuance of common stock to holders of Senior Notes claims	16,715
Issuance of common stock to Predecessor preferred unitholders	517
Issuance of common stock for the second lien equity investment	19,250
Issuance of common stock pursuant to the rights offering	255,750
Issuance of warrants	11,734
Change in additional paid-in capital	305,055
Par value of common stock	(20		)
Net increase in capital accounts	$	305,035

See Note 10, “Stockholders’ Equity (Members’ Deficit)” for additional information on the issuances of the Successor’s equity.

Fresh-Start Adjustments:


15)	Reflects a change in accounting policy from the entitlements method for natural gas production imbalances in accordance with the adoption of ASC 606.


16)	Reflects fair value adjustment for oil inventory.


17)	Reflects the adjustments to oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion. The following table summarizes the components of oil and natural gas properties as of the Convenience Date (in thousands):



	Successor		Predecessor
	Fair Value		Historical Book Value
Proved properties	$	1,511,083	$	4,635,867
Unproved properties	95,611		—
	1,606,694		4,635,867
Less: accumulated depletion and amortization	—		(3,916,889		)
	$	1,606,694	$	718,978


18)	Reflects the write-off of Predecessor goodwill.


19)	Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Convenience Date (in thousands):



	Successor		Predecessor
	Fair Value		Historical Book Value
Gas gathering assets	$	4,196	$	19,942
Office equipment and furniture	574		5,847
Buildings and leasehold improvements	57		836
Vehicles	1,311		1,549
	6,138		28,174
Less: accumulated depreciation	—		(13,657		)
	$	6,138	$	14,517

In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to value the Company’s other operating assets, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market approach was used to value the Company’s vehicles, using recent transactions of similar assets to determine the fair value from a market participant perspective.


20)	Reflects an adjustment for the intangible asset related to the Company’s nickel gas contract of $5.6 million and the write-off of deferred tax asset of $4.1 million.


21)	Reflects the adjustment of current portion of financing obligation to fair value and write-off of deferred rent.


22)	Reflects the adjustment of long-term portion of financing obligation to fair value.

23)

Primarily reflects the fair value adjustment of asset retirement obligations (“ARO”) to fair value of approximately $145.2 million, of which $136.8 million is reflected as long-term ARO and $8.4 million of current ARO shown in other current liabilities. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Refer to Note 8, “Asset Retirement Obligations” for further details of the Company's asset retirement obligations.


24)	Reflects the write-off of deferred tax liabilities.


25)	Reflects the cumulative impact of the fresh-start accounting adjustments discussed above and the elimination of Common units (Predecessor).

26) Reflects the fair value adjustment to the Potato Hills gas gathering assets on the non-controlling interest.

Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to the Petition Date as a direct result of the Final Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in “Reorganization items” in the Company’s unaudited consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):



	Predecessor
	Seven Months Ended July 31, 2017
Gain on settlement of Liabilities subject to compromise	$	452,129
Fresh-start accounting adjustments	781,520
Issuance of common shares and warrants	(214,140		)
Legal and other professional fees	(58,482		)
Recognition of additional unsecured claims	(31,346		)
Write-off of deferred financing costs and debt discounts	(21,361		)
Terminated contracts	165
Reorganization items	$	908,485

Reorganization costs incurred subsequent to the Emergence Date of $0.9 million are recorded in the selling, general and administrative expenses line item in the Company’s unaudited consolidated statements of operations for the two months ended September 30, 2017.

4. Impact of ASC 606 Adoption

In conjunction with the application of fresh-start accounting, we adopted ASC 606 - Revenue from Contracts with Customers (“ASC 606”). We adopted using the modified retrospective method, which fresh-start accounting allows us to apply

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

The impact of adoption on our current period results is as follows (in thousands):



	Successor
	Two Months Ended September 30, 2017
	Under ASC 606			Under ASC 605			Increase/(Decrease)
Revenues :
Oil sales	$	27,303		$	27,303		$	—
Natural gas sales	39,032			32,983			6,049
NGLs sales	13,465			11,470			1,995
Oil, natural gas and NGLs sales	79,800			71,756			8,044
Net losses on commodity derivative contracts	(32,352		)	(32,352		)	—
Total revenues	47,448			39,404			8,044
Costs and expenses :
Transportation, gathering, processing, and compression	8,044			—			8,044
Net loss	$	(37,236	)	$	(37,236	)	$	—

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

Revenue from Contracts with Customers

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

Natural gas and NGLs Sales

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

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

on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as Transportation, gathering, processing and compression expense in our consolidated statements of operations.

Oil sales

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


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

•

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

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC 606, for the period from August 1, 2017 through September 30, 2017, there was no material impact to the financial statements due to this change in accounting for our production imbalances.

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and 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. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from August 1, 2017 through September 30, 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

5. Debt

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



			Successor			Predecessor
Description	Interest Rate	Maturity Date	September 30, 2017			December 31, 2016
(in thousands)
Successor Credit Facility	Variable (1)	February 1, 2021	$	730,000		$	—
Successor term loan	Variable (2)	May 1, 2021	125,000			—
Senior Notes due 2024	9.0%	February 15, 2024	80,722			—
Predecessor Credit Facility	Variable(3)	April 16, 2018	—			1,269,000
Senior Notes due 2019	8.375% (4)	June 1, 2019	—			51,120
Senior Notes due 2020	7.875% (5)	April 1, 2020	—			381,830
Senior Notes due 2023	7.00%	February 15, 2023	—			75,634
Lease Financing Obligation	4.16%	August 10, 2020 (6)	16,354			20,167
Unamortized discount on Senior Notes			—			(13,167		)
Unamortized deferred financing costs			(9,164		)	(11,072		)
Total debt			$	942,912		$	1,773,512
Less:
Long-term debt classified as current			—			(1,753,345		)
Current portion of Lease Financing Obligation			(4,688		)	(4,692		)
Total long-term debt			$	938,224		$	15,475


(1)	Variable interest rate of 4.74% at September 30, 2017.


(2)	Variable interest rate of 8.74% at September 30, 2017.


(3)	Variable interest rate of 3.11% at December 31, 2016.


(4)	Effective interest rate of 21.45% at December 31, 2016.


(5)	Effective interest rate of 8.0% at December 31, 2016.


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

Successor Credit Facility

On the Effective Date, VNG, as borrower, has entered into the Successor Credit Facility, by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loans”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date is $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date is $730.0 million. The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). The next borrowing base redetermination is scheduled for August of 2018.

At September 30, 2017, there were $730.0 million of outstanding borrowings and $119.9 million of borrowing capacity under the Successor Credit Facility, after reflecting a $0.2 million reduction in availability for letters of credit (discussed below).

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

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

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

VNG is required to repay the Term Loans on the last day of each March, June, September and December (commencing with the first full fiscal quarter ended after the Effective Date), in each case, in an amount equal to 0.25% of the original principal amount of such Term Loans and, on the Maturity Date, the remainder of the principal amount of the Term Loans outstanding on such date, together in each case with accrued and unpaid interest on the principal amount to be paid but excluding the date of such payment. The table below shows the amounts of required payments under the Term Loan for each year as of September 30, 2017 (in thousands):



Year
2018	$	1,250
2019	1,250
2020	1,250
2021 through Maturity date	121,250

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

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

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

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

The Successor Credit Facility also contains certain financial covenants, including the maintenance of (i) the ratio of consolidated first lien debt of VNG and the Guarantors as of the date of determination to EBITDA for the most recently ended four consecutive fiscal quarter period for which financial statements are available of (a) 4.75 to 1.00 as of the last of any fiscal quarter ending from July 1, 2018 through December 31, 2018, (b) 4.50 to 1.00 as of the last day of any fiscal quarter ending from January 1, 2019 through December 31, 2019, (c) 4.25 to 1.00 as of the last day of any fiscal quarter ending from January 1, 2020 through September 30, 2020, and (d) 4.00 to 1.00 as of the last day of any fiscal quarter ending thereafter; (ii) an asset coverage ratio calculated as PV-9 of proved reserves, including impact of hedges and strip prices to first lien debt, of not less than 1.25 to 1.00 as tested on each January 1 and July 1 for the period from August 1, 2017 until August 1, 2018; and (iii) a current ratio, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending December 31, 2017, of not less than 1.00 to 1.00.

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

New Second Lien Notes Indenture

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of new 9.0% Senior Secured Second Lien Notes due 2024 (the “Senior Notes due 2024”) to certain eligible holders of their outstanding Old Second Lien Notes issued by the Predecessor and the Successor (the “Existing Notes”) in full satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The Senior Notes due 2024 were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

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

The Amended and Restated Indenture also contains customary events of default, including (i) default for thirty (30) days in the payment when due of interest on the New Notes; (ii) default in payment when due of principal of or premium, if any, on the New Notes at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency with respect to the Company or any of restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that taken together would constitute s significant subsidiary. If an event of default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding New Notes may declare all the New Notes to be due and payable immediately. If an event of default arises from certain events of bankruptcy or insolvency, with respect to the Company, any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries of the Company that, taken together, would constitute a significant subsidiary, all outstanding New Notes will become due and payable immediately without further action or notice.

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

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

On or after February 15, 2020, the New Notes will be redeemable, in whole or in part, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest:



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

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

Amended and Restated Intercreditor Agreement

On August 1, 2017, Citibank, N.A., as priority lien agent, and the Collateral Trustee entered into an Amended and Restated Intercreditor Agreement, which was acknowledged and agreed to by the Company and the Guarantors (the “Amended and Restated Intercreditor Agreement”), to govern the relationship of holders of the New Notes, the Lenders under the Company’s Successor Credit Facility and holders of other priority lien, second lien or junior lien obligations that the Company may issue in the future, with respect to the Collateral (as defined below) and certain other matters.

Under the Intercreditor Agreement, the Collateral Trustee may enforce or exercise any rights or remedies with respect to any Collateral, subject to a 180 day standstill period. However, the Collateral Trustee may not commence, or join with another party in commencing, any enforcement action with respect to any second-priority lien unless the first-priority liens have been discharged.

Amended and Restated Collateral Trust Agreement

On August 1, 2017, the Company, the Guarantors, the Trustee and the Collateral Trustee entered into an Amended and Restated Collateral Trust Agreement (the “Amended and Restated Collateral Trust Agreement”) pursuant to which the Collateral Trustee will receive, hold, administer, maintain, enforce and distribute all of its liens upon the Collateral for the benefit of the current and future holders of the New Notes and other obligations secured on an equal and ratable basis with the New Notes, if any.

Letters of Credit

At September 30, 2017, we had unused irrevocable standby letters of credit of approximately $0.2 million. The letters are being maintained as security related to the issuance of oil and natural gas well permits to recover potential costs of repairs, modification, or construction to remedy damages to properties caused by the operator. Borrowing availability for the letters of credit was provided under our Successor Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with marketing counterparties.

Predecessor’s Credit Facility, Old Second Lien Notes and Senior Notes

On the Effective Date, pursuant to the terms of the Final Plan, all outstanding obligations under the Predecessor’s Credit Facility, Old Second Lien Notes and unsecured senior notes were canceled. See Note 2, “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” for additional information.

Predecessor Covenant Violations

The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the obligations under the Predecessor’s Credit Facility, Old Second Lien Notes and Senior Notes. For the period from February 1, 2017 to the Effective Date, contractual interest, which was not recorded, on the Senior Notes was approximately $17.2 million. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.

Lease Financing Obligations

On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and related facilities and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the current fair market value. The Lease Financing Obligations also contain an early buyout option whereby the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

During the course of the Chapter 11 Cases, the Company assumed the Lease Financing Obligations.

6. Price and Interest Rate Risk Management Activities

In June 2017, we entered into derivative contracts primarily with counterparties that are also lenders under our Successor Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in over hedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points.

We have also historically entered into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Successor Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company did not have any interest rate swaps in place at September 30, 2017.

The following tables summarize oil, natural gas, and NGLs commodity derivative contracts in place at September 30, 2017.

Fixed-Price Swaps (NYMEX)



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Gallons	Weighted Average Fixed Price
October 1, 2017 – December 31, 2017	18,400,000	$	3.11	818,900	$	45.20	15,842,400	$	0.63
January 1, 2018 – December 31, 2018	70,242,000	$	3.00	3,059,200	$	46.47	56,721,000	$	0.60
January 1, 2019 - December 31, 2019	52,539,000	$	2.79	1,858,200	$	48.50	—	$	—
January 1, 2020 - December 31, 2020	47,227,500	$	2.75	1,393,800	$	49.53	—	$	—

Collars



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

Balance Sheet Presentation

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets 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 Consolidated Balance Sheets for the periods indicated (in thousands):



	Successor
	September 30, 2017
Offsetting Derivative Assets:	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	$	3,650		$	(3,396	)	$	254
Total derivative instruments	$	3,650		$	(3,396	)	$	254

Offsetting Derivative Liabilities:	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	$	(58,572	)	$	3,397		$	(55,175	)
Total derivative instruments	$	(58,572	)	$	3,397		$	(55,175	)



	Predecessor
	December 31, 2016
Derivative Liabilities:	Amount Presented in the Consolidated Balance Sheets
Interest rate derivative contracts	$	(125	)
Total derivative instruments	$	(125	)

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. All of our counterparties were participants in our Successor 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. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $3.7 million at September 30, 2017. We minimize the credit risk related to derivative instruments by: (i) entering into derivative instruments with counterparties that are also lenders in our Successor Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis

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



	Successor			Predecessor
	Two Months Ended September 30, 2017			Seven Months Ended July 31, 2017			December 31, 2016

Derivative asset (liability) at beginning of period, net	$	(24,895	)	$	(125	)	$	316,691
Purchases
Net premiums and fees received for derivative contracts	—			—			(2,444		)
Net losses on commodity and interest rate derivative contracts	(32,352		)	(24,858		)	(46,939		)
Settlements
Cash settlements paid (received) on matured commodity derivative contracts	2,326			(7		)	(226,876		)
Cash settlements paid on matured interest rate derivative contracts	—			95			13,398
Termination of derivative contracts	—			—			(53,955		)
Derivative liability at end of period, net	$	(54,921	)	$	(24,895	)	$	(125	)

7. Fair Value Measurements

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

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes acquisitions of oil and natural gas properties and other intangible assets. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction.

ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.

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



Level 1	Quoted prices for identical instruments in active markets.



Level 2	Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.



Level 3	Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

As of the Effective Date, the Company adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the Convenience Date of July 31, 2017. See Note 3, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company.

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

Financing arrangements. The carrying amounts of our bank borrowings outstanding, including the term loans, represent their approximate fair value because our current borrowing rates are variable and do not materially differ from market

rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of September 30, 2017, the carrying value of our Senior Notes due 2024 approximates its fair value. The Senior Notes due 2024 were issued at the Effective Date to holders of the predecessor Senior Notes due 2023 wherein they received full value of their claims and with terms that satisfied all counterparties. We consider the inputs to the valuation of our Senior Notes due 2024 to be Level 2.

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

As of December 31, 2016 (Predecessor), we had one remaining interest rate swap derivative contract, which expired in February 2017. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input.

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

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



	Successor
	September 30, 2017
	Fair Value Measurements			Assets/Liabilities
	Using Level 2			at Fair Value
Assets:
Commodity price derivative contracts	$	254		$	254
Total derivative instruments	$	254		$	254
Liabilities:
Commodity price derivative contracts	$	(55,175	)	$	(55,175	)
Total derivative instruments	$	(55,175	)	$	(55,175	)



	Predecessor
	December 31, 2016
	Fair Value Measurements			Assets/Liabilities
	Using Level 2			at Fair Value
Liabilities:
Interest rate derivative contracts	$	(125	)	$	(125	)
Total derivative instruments	$	(125	)	$	(125	)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:



	Predecessor
	Nine Months Ended September 30, 2016
	(in thousands)
Unobservable inputs, beginning of period	$	(5,933	)
Total gains	9,381
Settlements	(4,608		)
Unobservable inputs, end of period	$	(1,160	)

Change in fair value included in earnings related to derivatives still held as of September 30,	$	223

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

Our Predecessor applied the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represented the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill was assessed for impairment annually on October 1 or whenever indicators of impairment existed. The goodwill test was performed at the reporting unit level, which represented our oil and natural gas operations in the United States. If indicators of impairment were determined to exist, an impairment charge was recognized if the carrying value of goodwill exceeded its implied fair value. We utilized a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimates of the fair value of our reporting unit and could result in an impairment charge.

Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations. These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 8, “Asset Retirement Obligations,” in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate; and (4) the average inflation factor. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

8. Asset Retirement Obligations

The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):



Asset retirement obligations as of December 31, 2016 (Predecessor)	$	272,436
Liabilities added during the current period	555
Accretion expense	6,795
Retirements	(1,161		)
Liabilities related to assets divested	(10,107		)
Change in estimate	(29		)
Asset retirement obligation at July 31, 2017 (Predecessor)	268,489
Fresh-start adjustment ⁽¹⁾	(123,320		)
Asset retirement obligation at July 31, 2017 (Successor)	145,169
Liabilities added during the current period	206
Accretion expense	1,478
Retirements	(317		)
Asset retirement obligation at September 30, 2017 (Successor)	146,536
Less: current obligations	(6,457		)
Long-term asset retirement obligation at September 30, 2017 (Successor)	$	140,079

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

9. Commitments and Contingencies

Transportation Demand Charges

As of September 30, 2017, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to three years and require 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 September 30, 2017. 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.



	September 30, 2017
	(in thousands)
October 1, 2017 - December 31, 2017	$	356
2018	1,009
2019	821
2020	410
Total	$	2,596

Legal Proceedings

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

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

The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

We are defendants in certain legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

10. Stockholders’ Equity (Members’ Deficit)

Cancellation of Units and Issuance of Common Stock

As previously discussed, all outstanding Preferred Units issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% of outstanding shares of Common Stock and (ii) Preferred Unit Warrants, in full and final satisfaction of their interests. Further, all common equity of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders of the common equity received Common Unit Warrants, in full and final satisfaction of their interests. Please see further discussion below regarding the issuance of new warrants.

On the Effective Date, the Company issued the following in accordance with the Final Plan:


•	678,464 shares of New Common Stock were issued pro rata to holders of claims arising under the Senior Notes;


•	1,283,333 shares of New Common Stock were issued pro rata to holders of the Old Second Lien Notes in exchange for a fully committed $19.25 million investment;


•	678,405 shares of New Common Stock were issued to participants in the 1145 rights offering extended by the Debtors to certain holders of claims arising under the Senior Notes (including certain of the commitment parties party to the Backstop Commitment Agreement);


•	7,846,595 shares of New Common Stock were issued to participants who were eligible to participate in the accredited investor rights offering extended by the Debtors to certain holders of claims arising under the Senior Notes (including certain of the commitment parties party to the Backstop Commitment Agreement);


•	1,023,000 shares of New Common Stock were issued to commitment parties under the Amended and Restated Backstop Commitment Agreement in respect of the premium due thereunder;


•	8,525,000 shares of New Common Stock were issued to commitment parties under the Amended and Restated Backstop Commitment Agreement in connection with their backstop obligation thereunder together with 1,482,021 shares of New Common Stock reflecting shares purchased by such commitment parties in respect of unsubscribed shares in the rights offerings; and


•	20,983 shares of New Common Stock were issued to holders of Old Vanguard’s Preferred Units.

Warrant Agreement

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

subject to dilution. The expiration date of the Warrants will be February 1, 2021. The strike price for the Preferred Unit New Warrants is $44.25, and the strike price for the Common Unit New Warrants is $61.45.

The Company allocated approximately $11.7 million of the Enterprise Value to the warrants which is reflected in “Successor Additional paid-in capital” on the unaudited condensed consolidated balance sheet at September 30, 2017.

Management Incentive Plan

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

The maximum number of shares of common shares available for issuance under the 2017 MIP is 2,233,333 shares.

The 2017 MIP will be administered by the Committee or, in certain instances, its designee. Employees, directors, and consultants of the Company and its subsidiaries will be eligible to receive awards of stock options, restricted stock, restricted stock units or other stock-based awards at the Committee or its designee's discretion.

The Board may amend, modify, suspend, or terminate the 2017 MIP in its discretion; however no amendment, modification, suspension or termination may materially and adversely affect any award previously granted without the consent of the participant or the permitted transferee of the award. No grant will be made under the 2017 Plan more than 10 years after its effective date.

Dividends/Distributions

Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In February 2016, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor currently has no intention of paying cash dividends and any future payment of cash dividends would be subject to the restrictions in the agreements governing the Successor Credit Facility and the Senior Notes due 2024.

Earnings Per Share/Unit

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

The diluted earnings per share calculation excludes approximately 1.3 million warrants that were antidilutive for the two months ended September 30, 2017. For the one month and seven months ended July 31, 2017, 13.5 million phantom units were excluded from the calculation of diluted earnings per unit as they were antidilutive. For the three months and nine months period ended September 30, 2016, 2.6 million phantom units were excluded from the calculation of diluted earnings per unit for each period, due to their antidilutive effect as we were in a loss position.

11. Unit-Based Compensation

Effect of Emergence from Bankruptcy on Unit-Based Compensation

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

Second Amended and Restated Employment Agreements

On August 1, 2017, the Company entered into amended and restated employment agreements (the “Employment Agreements”) with each of Scott W. Smith and Britt Pence (each, an “Executive” and collectively, the “Executives”). The Employment Agreements were effective on the Effective Date, and supersede prior employment agreements dated January 1, 2016. The initial term of the Employment Agreements ends on January 1, 2019, with a subsequent twelve (12) month term extension automatically commencing on January 1, 2019, provided that neither the Company nor the Executives deliver a timely non-renewal notice prior to the expiration date. On October 31, 2017, the Company entered into an employment agreement with R. Scott Sloan. The initial term of Mr. Sloan’s employment agreement ends on December 31, 2020, with a subsequent twelve (12) month term extension automatically commencing on January 1, 2021, provided that neither the Company nor the Executives deliver a timely non-renewal notice prior to the expiration date.

The Employment Agreements provide that (i) Mr. Smith is entitled to an annual base salary of $650,000, which will increase to $700,000 on January 1, 2018; (ii) Mr. Sloan is entitled to an annual base salary of $510,000, which is subject to review at least annually; and (iii) Mr. Pence is entitled to an annual base salary of $450,000, which will increase to $460,000 on January 1, 2018. In addition, the Company’s Board has the discretion to increase the base salaries of Messrs. Smith, Sloan and Pence at any time. Subject to certain terms and conditions, the Board may not reduce an Executive’s base salary without his prior written approval.

Each Executive shall be eligible to receive an annual bonus in an amount to be determined by the Board or compensation committee of the Board (the “Compensation Committee”). Each Executive will also be eligible to receive bonus payments through the year ended December 31, 2017 in accordance with Old Vanguard’s 2017 pre-emergence annual cash bonus program. The Employment Agreements provide that Messrs. Smith, Sloan and Pence are eligible to participate in the benefit programs generally available to senior executives of the Company, including the management incentive plan (“MIP”) to be implemented by the Board, in its sole discretion.

In the event of the Company’s Change in Control (as defined in the Employment Agreements), the Executives are entitled to certain change in control payments and benefits under the Employment Agreements. If, during the twelve (12) months immediately following the occurrence of a Change of Control of the Company, the Executive is terminated by the Company without Cause or resigns for Good Reason (each as defined below), the Executive will be entitled to receive within ten (10) business days after the date of his termination, accrued compensation and reimbursements listed in the Employment Agreements, and (ii) on the sixtieth (60th) day following the date of termination, a lump sum payment of an amount equaling two (2) times his then-current base-salary and annual bonus.

Under the Employment Agreements, Messrs. Smith, Sloan and Pence are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by the Company without Cause or termination by any such Executive for Good Reason (and except with respect to a Change of Control within a year of the Effective Date, as described above), the Executive is entitled to receive on the sixtieth (60th) day following the date of termination, a lump sum payment of an amount equal to two and a half (2.5) times the Executive’s then-current base salary. Upon an executive’s termination by Disability (as defined below) or death, the Executive is entitled to accrued compensation and reimbursements. As a condition to receiving any of the Change of Control or severance payments and benefits provided in the Employment Agreements, the terminated Executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

The Employment Agreements generally define the term “Cause” to mean (i) the Executive’s commission of theft, embezzlement, any other act of dishonesty relating to his employment with the Company or any willful violation of any law, rules, or regulation applicable to the Company, including, but not limited to, those laws, rules, or regulations established by the SEC or any self-regulatory organization having jurisdiction or authority over the Executive or the Company; (ii) the Executive’s conviction of, or Executive’s plea of guilty or nolo contendere to, any felony or any other crime involving fraud, dishonesty, or moral turpitude; (iii) a determination by the Board that the Executive has materially breached his Employment Agreement (other than during any period of Disability) where such breach is not remedied within ten (10) business days after written demand by the Board for substantial performance is actually received by the Executive which specifically identifies the manner in which the Board believes the Executive has so breached; or (iv) the Executive’s willful failure to perform the reasonable and customary duties of his position as stated in the Employment Agreement which such failure is not remedied within ten (10) business days after written demand by the Board for substantial performance is actually received by the Executive which specifically identifies the nature of such failure.

The Employment Agreements define the term “Good Reason” to mean the following, without the Executive’s written consent: (a) a material reduction in the Executive’s authority, duties, or responsibilities (excluding any changes to the foregoing resulting from the Company’s emergence from the Chapter 11 Cases); (b) a material reduction in the Executive’s base salary, other than a reduction affecting senior management similarly and in no event more than 10% from the Executive’s base salary

in effect on that date; (c) the Executive’s removal from his position as stated in the Employment Agreement, other than for Cause or by death or Disability, to a position that is not at least equivalent in authority and duties (excluding his removal as a member of the Board, as applicable); (d) relocation of the Executive’s principal place of business to a location fifty (50) or more miles from its location as of the date of the Employment Agreement; (e) a material breach by the Company of the Employment Agreement, which materially adversely affects the Executive; (f) the Company’s failure to make any material payment to the Executive required to be made under the Employment Agreement, or (g) the Board or the Compensation Committee (x) fails to make grants of initial awards (“Initial Grants”) under the MIP within ninety (90) days following the Effective Date or (y) fails to grant the Executive an Initial Grant substantially equivalent in value, on the award date, to the lesser of (I) Executive’s past equity awards or (II) grants made at median to similarly situated Executives employed by other companies within the Company’s peer group selected by the Board or a committee thereof based on the recommendation of an independent compensation consultant to the Board or a committee thereof.

The Employment Agreements generally define the term “Disability” to mean the Executive’s inability to substantially perform his duties as an employee of the Company as a result of sickness or injury, and continued inability to perform any such duties for a period of more than 180 consecutive days in any 12 month period.

The Employment Agreements contain standard non-competition, non-solicitation and confidentiality provisions.

Management Incentive Plan

As discussed in Note 10, “Stockholders’ Equity (Members’ Deficit),” on August 22, 2017, the Company’s board of directors approved the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “2017 MIP ”), which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders.

There were no grants under the 2017 MIP from the Effective Date through September 30, 2017.

12. Income Taxes

Effective August 1, 2017, upon consummation of the Final Plan, the Successor became a C corporation subject to federal and state income taxes. For the two months ended September 30, 2017, we recorded no income tax expense or benefit. The significant difference between our effective tax rate and the federal statutory income tax rate of 35% is primarily due to the effect of changes in the Company’s valuation allowance. During the two months ended September 30, 2017, 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.

13. Shelf Registration Statement

Registration Rights Agreement

On the Effective Date, in accordance with the Final Plan and that certain Amended and Restated Backstop Commitment and Equity Investment Agreement, dated as of February 24, 2017, as amended and restated on May 23, 2017 (as may have been further amended from time to time, the “Amended and Restated Backstop Commitment Agreement”), the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with certain recipients of shares of New Common Stock distributed on the Effective Date that were party to the Amended and Restated Backstop Commitment Agreement (including certain of their affiliates and related funds), in accordance with the terms set forth in the Final Plan (collectively, the “Registration Rights Holders”).

The Registration Rights Agreement required the Company to file a shelf registration statement (“Initial Shelf Registration Statement”) within ninety (90) calendar days following the Effective Date that includes the Registrable Securities (as defined in the Registration Rights Agreement) whose inclusion has been timely requested, provided, however, that the Company is not required to file or cause to be declared effective an Initial Shelf Registration Statement unless the request from Registration Rights Holders amounts to at least 20% of all Registrable Securities. The Registration Rights Agreement also provides the Registration Rights Holders the ability to demand registrations or underwritten shelf takedowns subject to certain requirements and exceptions.

In addition, if the Company proposes to register shares of New Common Stock in certain circumstances, the Registration Rights Holders will have certain “piggyback” registration rights, subject to restrictions set forth in the Registration Rights Agreement, to include their shares of New Common Stock in the registration statement.

The Registration Rights Agreement also provides that (i) for so long as the Company is subject to the requirements to publicly file information or reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, the Company will timely file all information and reports with the SEC and comply with all such requirements and (b) if the Company is not subject to the requirements of Section 13 or 15(d) of the Exchange Act, the Company will make available the information necessary to comply with Section 4(a)(7) of the Securities Act and Rule 144 and Rule 144A, if available with respect to resales of the Registrable Securities under the Securities Act, at all times, all to the extent required from time to time to enable Registration Rights Holders to sell Registrable Securities without registration under the Securities Act pursuant to the abovementioned exemptions or any other rule or regulation hereafter adopted by the SEC.

The Company filed the Initial Shelf Registration Statement on October 30, 2017. The Company is required to use commercially reasonable efforts to cause the Initial Shelf Registration Statement to be declared effective by the Commission as promptly as practicable, and shall use its commercially reasonable efforts to keep such Initial Shelf Registration Statement continuously effective.

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 period from August 1, 2017 through September 30, 2017 (Successor) and January 1, 2017 through July 31, 2017 (Predecessor) and the three and nine months ended September 30, 2016 (Predecessor) and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Predecessor’s 2016 Annual Report, though as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized company subsequent to July 31, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, July 31, 2017.

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

Overview


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


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


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Big Horn Basin in Wyoming and Montana;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

As of September 30, 2017, based on internal reserve estimates, our total estimated proved reserves were 1,995 Bcfe, of which approximately 73% were natural gas reserves, 13% were oil reserves and 14% were NGLs reserves. Of these total estimated proved reserves, approximately 64%, or 1,283 Bcfe, were classified as proved developed. Also, at September 30, 2017, we owned working interests in 11,462 gross (4,020 net) productive wells. Our operated wells accounted for approximately 46% of our total estimated proved reserves at September 30, 2017. Our average net daily production for the nine months ended September 30, 2017 and our Predecessor’s for the year ended December 31, 2016 was 378 MMcfe/day and 433 MMcfe/day, respectively. We have interests in approximately 677,869 gross undeveloped leasehold acres surrounding our existing wells.

Chapter 11 Reorganization

On February 1, 2017, the Predecessor and certain subsidiaries (such subsidiaries, together with the Predecessor, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 Cases were administered under the caption “In re Vanguard Natural Resources, LLC, et al.”

Prior to the filing of the Bankruptcy Petitions, on February 1, 2017, we entered into a restructuring support agreement (the “Initial RSA”). The Debtors entered into the Initial RSA with: (i) certain holders of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”), constituting at the time of signing approximately 52% of such holders (the “Consenting 2020 Noteholders”); (ii) certain holders of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and together with the Senior Notes due 2020, the “Senior Notes”), constituting at the time of signing approximately 10% of such holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders”); and (iii) certain holders of the Old Second Lien Notes, constituting at the time of signing approximately 92% of such holders (the “Consenting Second Lien Noteholders”).

On July 18, 2017, the Bankruptcy Court entered the Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Confirmation Order”), which approved and confirmed the Debtors’ Modified Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (the “Final Plan”). The Final Plan provides for the reorganization of the Debtors as a going concern and will significantly reduce the long-term debt and annual interest payments of the Successor. During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017 (the “Effective Date”). The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Predecessor’s equity securities outstanding immediately before the Effective Date (including any unvested restricted units held by employees or officers of the Debtor, or options and warrants to purchase such securities) have been cancelled and are of no further force or effect as of the Effective Date. Under the Final Plan, the Debtors’ new organizational documents became effective on the Effective Date. The Successor’s new organizational documents authorize the Successor to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Final Plan on the Effective Date. In addition, on the Effective Date, the Successor entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Successor reserved for issuance 20.1 million outstanding shares of common stock, $0.001 par value. (“Common Stock”).

Plan of Reorganization

Upon emergence, pursuant to the terms of the Final Plan, the following significant transactions occurred:


•	The Predecessor transferred all of its membership interests in VNG, a Kentucky limited liability company and the Predecessor’s wholly owned first-tier subsidiary, to the Successor (formerly known as VNR Finance Corp.). VNG directly or indirectly owned all of the other subsidiaries of the Predecessor. As a result of the foregoing and certain

other transactions, the Successor is no longer a subsidiary of the Predecessor and now owns all of the former subsidiaries of the Predecessor;

•


•	The Successor issued approximately $80.7 million aggregate principal amount of New Notes to certain eligible holders of their outstanding 7% Senior Secured Second Lien Notes due 2023 (the “Old Second Lien Notes”) in full satisfaction of their claim of approximately $80.7 million related to the Old Second Lien Notes held by such holders;


•	The Predecessor’s Senior Notes were cancelled and the Consenting Senior Noteholders received their pro rata share of 3.38% (subject to dilution) of the Common Stock, in full and final satisfaction of their claims;


•	The Predecessor completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $275.0 million of gross proceeds. The rights offering resulted in the issuance of Common Stock, representing approximately 89.92% of outstanding shares of Common Stock, to holders of claims arising under the Senior Notes and to the Backstop Parties;

•


•	Additional shares of Common Stock, representing eleven percent of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);


•	All outstanding Preferred Units (defined below) issued and outstanding immediately prior to the Effective Date were cancelled and the holders thereof received their pro rata shares of (i) 3% of outstanding shares of Common Stock and (ii) Preferred Unit Warrants (as defined below), in full and final satisfaction of their interests;


•	All common equity of the Predecessor issued and outstanding immediately prior to the Effective Date were cancelled and the holders of the common equity received Common Unit Warrants (as defined below), in full and final satisfaction of their interests;

•

The Successor entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Successor issued (i) to electing holders of the Predecessor’s (A) 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), (B) 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and (C) 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units” and, together with the Series A Preferred Units and Series B Preferred Units, the “Preferred Units”), three and a half year warrants (the “Preferred Unit Warrants”), which will be exercisable to purchase up to 621,649.49 shares of the Common Stock as of the Effective Date, subject to dilution; and (ii) to electing holders of the Predecessor’s common units representing limited liability company interests, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”) which will be exercisable to purchase up to 640,875.75 shares of the Common Stock as of the Effective Date, subject to dilution. The expiration date of the Warrants will be February 1, 2021. The strike price for the Preferred Unit Warrants is $44.25, and the strike price for the Common Unit Warrants is $61.45;

•

By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. Our current Board consists of seven members, including our and our Predecessor’s Chief Executive Officer. Our Chief Financial Officer was initially appointed as a director upon emergence and became our Chief Financial Officer as well, following the resignation of our Predecessor’s Chief Financial Officer;


•	Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders; and


•	On the Effective Date, the Successor reserved for issuance 20,100,000 shares of Common Stock.

Listing on the OTCQX Market

Accounting Policies

Upon emergence from bankruptcy, we had multiple changes to our accounting policies:

•

We applied fresh-start accounting in accordance with Accounting Standards Codification (“ASC”) 852, which resulted in our becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of our emergence from the Chapter 11 Cases on August 1, 2017. The fair values of our assets and liabilities differ materially from the recorded values of our assets and liabilities as reflected in our Predecessor’s historical consolidated balance sheets;


•	We changed our method of accounting for natural gas and oil properties from the full cost method of accounting (the “Full Cost Method”) to the successful efforts method of accounting (the “Successful Efforts Method”);


•	We have elected to adopt the new standard for revenue recognition under Accounting Standards Codification 606 (“ASC 606”) upon emergence. The new guidance requires us to recognize revenue upon transfer of goods or services to a customer at an amount that reflects the expected consideration to be received in exchange for those goods or services; and


•	We elected to change from a pass-through entity for tax purposes to a c-corp and, accordingly, a taxable entity;

Fresh-Start Accounting

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

We adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the fair value of the Successor Company’s total assets or the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to "Plan of Reorganization" above for the terms of our reorganization under the Final Plan. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start

accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we will have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Final Plan, our unaudited condensed consolidated financial statements subsequent to July 31, 2017 may not be comparable to our unaudited condensed consolidated financial statements prior to July 31, 2017, as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Hedging Activities

In June 2017, we entered into commodity derivative contracts primarily with counterparties that are also lenders under our Successor Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production commencing with August 2017 production volumes.

We have implemented a hedging program for approximately 94%, 94%, 82% , and 75% of our anticipated crude oil production from proved developed producing reserves in 2017, 2018, 2019, and 2020, respectively, with 100% in the form of fixed-price swaps in 2017 and 2018. Approximately 85%, 89%, 81%, and 83% of our anticipated natural gas production in 2017, 2018, 2019, and 2020, respectively, was hedged, with 100% in the form of fixed-price swaps in 2017 and 2018. NGLs production was under fixed-price swaps for approximately 49% and 47% of anticipated production in 2017 and 2018, respectively. These hedges will provide some cash flow certainty regardless of the volatility in commodity prices.

Capital Development

We currently anticipate a capital expenditures budget of approximately $103 million to $108 million in 2017. Total capital expenditures were approximately $70.7 million during the nine months ended September 30, 2017 and we expect to incur approximately $32 million to $37 million during the final quarter of 2017. We have focused our 2017 capital in three areas: the Green River Pinedale, the Gulf Coast East Haynesville field and the Mamm Creek field in the Piceance Basin. In the Green River Basin we will participate as a non-operated partner in the drilling and completion of vertical and horizontal natural gas wells in Pinedale Field. In the Gulf Coast Basin East Haynesville Field, we have drilled six vertical wells. Of the six wells drilled, four have been completed in the Haynesville sand, one is testing the Smackover and one is a dry hole. Also, in Mamm Creek Field we are expecting to begin our infill development program at the end of the fourth quarter. Our capital expenditures budget for 2017 is dependent upon future commodity prices and is subject to change. During the nine months ended September 30, 2017, we drilled seven gross (6.3 net) operated wells and completed four gross (3.7 net) operated wells. In addition we participated in the drilling of 139 gross (19.7 net) non-operated wells and in the completion of 108 gross (15.3 net) non-operated wells.

Results of Operations

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The table included below sets forth financial and operating data for the periods indicated (in thousands). The two months ended September 30, 2017 (Successor Company) and the one month ended July 31, 2017 (Predecessor Company) are distinct reporting periods as a result of our application of fresh-start accounting at the Convenience Date and may not be comparable to prior periods.



	Successor			Predecessor
	Two Months			One Month			Three Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Revenues:
Oil sales	$	27,303		$	11,820		$	41,999
Natural gas sales	39,032			4,412			52,454
NGLs sales	13,465			4,792			10,733
Oil, natural gas and NGLs sales	79,800			21,024			105,186
Net gains (losses) on commodity derivative contracts	(32,352		)	(12,019		)	21,099
Total revenues	$	47,448		$	9,005		$	126,285
Costs and expenses:
Production:
Lease operating expenses	26,447			11,787			39,386
Transportation, gathering, processing, and compression	8,044			—			—
Production and other taxes	5,737			1,983			11,823
Depreciation, depletion, amortization, and accretion	27,578			7,328			32,096
Impairment of goodwill	—			—			252,676
Exploration expense	105			—			—
Other selling, general and administrative expenses	7,194			8,027			8,708
Non-cash compensation	—			711			2,746
Total costs and expenses	$	75,105		$	29,836		$	347,435
Other income (expense):
Interest expense	(9,615		)	(5,003		)	(22,976		)
Net gains on interest rate derivative contracts	—			—			764
Net loss on acquisitions or divestitures of oil and natural gas properties	—			—			(2,117		)
Other	36			472			111
Reorganization items	—			988,452			—


(a)	During the three and nine months ended September 30, 2017 and September 30, 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

Revenues

Oil, natural gas and NGLs sales were $79.8 million, $21.0 million and $105.2 million for the two months ended September 30, 2017 (Successor), the one month ended July 31, 2017 (Predecessor) and the three months ended September 30, 2016 (Predecessor), respectively. The key oil, natural gas and NGLs revenue measurements were as follows:



	Successor		Predecessor^(a)
	Two Months		One Month		Three Months
	Ended		Ended		Ended
	September 30, 2017		July 31, 2017		September 30, 2016
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	43.70	$	40.32	$	39.94
Natural Gas (Price/Mcf) ^(b)	$	2.51	$	0.53	$	1.92
NGLs (Price/Bbl)	$	25.82	$	17.09	$	12.15
Average realized prices, including hedges^(c):
Oil (Price/Bbl)	$	40.45	$	40.32	$	60.25
Natural Gas (Price/Mcf)	$	2.63	$	0.53	$	3.13
NGLs (Price/Bbl)	$	21.90	$	17.09	$	13.32
Average NYMEX prices:
Oil (Price/Bbl)	$	48.94	$	46.68	$	44.95
Natural Gas (Price/Mcf)	$	2.97	$	3.07	$	2.82
Total production volumes:
Oil (MBbls)	625		293		1,051
Natural Gas (MMcf)	15,537		8,353		27,381
NGLs (MBbls)	521		280		883
Combined (MMcfe)	22,414		11,794		38,988
Average daily production volumes:
Oil (Bbls/day)	10,242		9,456		11,428
Natural Gas (Mcf/day)	254,702		269,450		297,619
NGLs (Bbls/day)	8,548		9,043		9,599
Combined (Mcfe/day)	362,402		380,447		423,787


(a)	During the three months ended September 30, 2017 and 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.


(b)	Includes expenses related to transportation, gathering, processing, and compression of natural gas production.


(c)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

The decrease in oil, natural gas and NGLs sales was due primarily to an overall decrease in production primarily due to divestitures completed during 2017. Average daily production decreased to approximately 362 MMcfe/day and 380 MMcfe/day for the two months ended September 30, 2017 (Successor) and for one month ended July 31, 2017 (Predecessor), respectively, from approximately 424 MMcfe/day for the three months ended September 30, 2016 (Predecessor).

On a Mcfe basis, crude oil, natural gas and NGLs accounted for 16%, 70% and 14%, respectively, of our production during the three months ended September 30, 2017 and 2016.

Hedging and Price Risk Management Activities

We recognized a net loss on commodity derivative contracts of $32.4 million and $12.0 million, and a net gain on commodity derivative contracts of $21.1 million, for the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively. 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 consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and other customary charges. Lease operating expenses were $26.4 million, $11.8 million, and $39.4 million for the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively. The decrease in lease operating expenses is mainly due to divestitures completed during the year as well as a result of cost reduction initiatives including price negotiations with field vendors in light of the current commodity price environment.

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 7.2%, 9.4%, and 11.2% for the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively. The percentage was lower during the current period primarily due to the utilization of production and ad valorem tax rates from prior periods based on actual tax assessments.

Depreciation, depletion, amortization, and accretion expense was $27.6 million, $7.3 million and $32.1 million for the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively. The decrease in depletion expense is due to a lower depletion base as a result of the non-cash ceiling impairment charges recorded during 2016 and the divestitures of oil and natural gas properties completed in 2016 and 2017.

We adjust our depletion rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs. Thus, our depletion rate could change significantly in the future. Depletion expense is not comparable between Successor and Predecessor periods as a result our implementation of fresh-start accounting upon bankruptcy emergence whereupon the carrying value of our proved oil and gas properties on our balance sheet was restated to fair value. The restatement resulted in an increase in the amortization base which led to a corresponding increase in the depletion rate per equivalent unit of production for the two months ended September 30, 2017. Also upon emergence, we changed our method of accounting for oil and gas exploration and development activities from the full-cost method to the successful-efforts method of accounting.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. During the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), selling, general and administrative expenses were $7.2 million, $8.0 million and $8.7 million, respectively. General and administrative expenses in 2017 have been impacted by costs incurred in connection with the Chapter 11 Cases.

In addition, we incurred non-cash compensation expense of $0.7 million and $2.7 million for the one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively.

Other Income and Expense

Interest expense was $9.6 million, $5.0 million and $23.0 million during the two months ended September 30, 2017 (Successor), one month ended July 31, 2017 (Predecessor) and three months ended September 30, 2016 (Predecessor), respectively. The Successor Company has lower interest expense resulting from the reduction in its borrowings under the reserve-based revolving credit facility. The decrease in interest expense during the Predecessor period was primarily due to the discontinuance of interest on our senior notes that were cancelled as part of our Chapter 11 Cases.

Reorganization Items

We incurred reorganization gain of $988.5 million for the one month ended July 31, 2017 (Predecessor). The Predecessor gain resulted from the gain on the discharge of debt and fresh-start adjustments upon emergence from chapter 11 bankruptcy. See Note 3,“Fresh-Start Accounting” to the consolidated financial statements for further details.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The table included below sets forth financial and operating data for the periods indicated (in thousands). The two months ended September 30, 2017 (Successor), the one month ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy on July 31, 2017 and may not be comparable to prior periods.



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Revenues:
Oil sales	$	27,303		$	97,496		$	127,594
Natural gas sales	39,032			113,587			121,756
NGLs sales	13,465			35,565			30,752
Oil, natural gas and NGLs sales	79,800			246,648			280,102
Net losses on commodity derivative contracts	(32,352		)	(24,887		)	(15,752		)
Total revenues	$	47,448		$	221,761		$	264,350
Costs and expenses:
Production:
Lease operating expenses	26,447			87,092			120,228
Transportation, gathering, processing and compression	8,044			—			—
Production and other taxes	5,737			21,186			29,967
Depreciation, depletion, amortization, and accretion	27,578			58,384			118,935
Impairment of oil and natural gas properties	—			—			365,658
Impairment of goodwill	—			—			252,676
Exploration expense	105			—			—
Other selling, general and administrative expenses	7,194			28,099			28,163
Non-cash compensation	—			711			7,721
Total costs and expenses	$	75,000		$	195,472		$	923,348
Other income (expense):
Interest expense	(9,615		)	(35,276		)	(72,612		)
Net gains (losses) on interest rate derivative contracts	—			30			(6,061		)
Net loss on acquisitions or divestitures of oil and natural gas properties	—			—			(3,782		)
Gain on extinguishment of debt	—			—			89,714
Other	36			783			363
Reorganization items	—			908,485			—


(a)	During the three and nine months ended September 30, 2017 and September 30, 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

Revenues

Oil, natural gas and NGLs sales were $79.8 million, $246.6 million and $280.1 million for the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively. The key oil, natural gas and NGLs revenue measurements were as follows:



	Successor		Predecessor^(a)
	Two Months		Seven Months		Nine Months
	Ended		Ended		Ended
	September 30, 2017		July 31, 2017		September 30, 2016
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	43.70	$	43.33	$	34.87
Natural Gas (Price/Mcf) ^(b)	$	2.51	$	2.05	$	1.46
NGLs (Price/Bbl)	$	25.82	$	17.87	$	10.84
Average realized prices, including hedges^(c):
Oil (Price/Bbl)	$	40.45	$	43.34	$	53.69
Natural Gas (Price/Mcf)	$	2.63	$	2.05	$	2.95
NGLs (Price/Bbl)	$	21.90	$	17.87	$	12.31
Average NYMEX prices:
Oil (Price/Bbl)	$	48.94	$	49.72	$	40.85
Natural Gas (Price/Mcf)	$	2.97	$	3.22	$	2.28
Total production volumes:
Oil (MBbls)	625		2,250		3,660
Natural Gas (MMcf)	15,537		55,375		83,592
NGLs (MBbls)	521		1,990		2,837
Combined (MMcfe)	22,414		80,814		122,573
Average daily production volumes:
Oil (Bbls/day)	10,242		10,613		13,356
Natural Gas (Mcf/day)	254,702		261,201		305,081
NGLs (Bbls/day)	8,548		9,387		10,355
Combined (Mcfe/day)	362,402		381,198		447,347


(a)	During the nine months ended September 30, 2017 and 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.


(b)	Includes expenses related to transportation, gathering, processing, and compression of natural gas production.


(c)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

The overall increase in oil, natural gas and NGLs sales was due primarily to the increase in the average realized oil, natural gas and NGLs prices, excluding hedges. The increase in price was partially offset by an overall decrease in average daily production which decreased to approximately 362 MMcfe/day and 381 MMcfe/day for the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, from approximately 447 MMcfe/day for the nine months ended September 30, 2016 (Predecessor). The decrease in average daily production was primarily due to divestitures completed during 2017.

On an Mcfe basis, crude oil, natural gas and NGLs accounted for 17%, 69% and 15%, respectively, of our production during the nine months ended September 30, 2017 compared to 18%, 68% and 14%, respectively, of our production during the same period in 2016.

Hedging and Price Risk Management Activities

We recognized a net loss on commodity derivative contracts of $32.4 million, $24.9 million and $15.8 million, during the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine

months ended September 30, 2016 (Predecessor), respectively. 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 consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and other customary charges. Lease operating expenses were $26.4 million, $87.1 million, and $120.2 million for the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively. The decrease in lease operating expenses is mainly due to divestitures completed during the year as well as a result of cost reduction initiatives including price negotiations with field vendors in light of the current commodity price environment.

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 7.2%, 8.6%, and 10.7% for the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively. The percentage was lower during the current period primarily due to the utilization of production and ad valorem tax rates from prior periods based on actual tax assessments.

Depreciation, depletion, amortization, and accretion expense was $27.6 million, $58.4 million and $118.9 million for the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively. The decrease in depletion expense is due to a lower depletion base as a result of the non-cash ceiling impairment charges recorded during 2016 and the divestitures of oil and natural gas properties completed in 2016 and 2017.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. During the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), selling, general and administrative expenses were $7.2 million, $28.1 million and $28.2 million, respectively. General and administrative expenses in 2017 have been impacted by costs incurred in connection with the Chapter 11 Cases.

In addition, we incurred non-cash compensation expense of $0.7 million and $7.7 million for the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively.

Other Income and Expense

Interest expense was $9.6 million, $35.3 million and $72.6 million during the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016

(Predecessor), respectively. The Successor Company has lower interest expense due to lower borrowing base. The decrease in interest expense during the Predecessor period was primarily due to the discontinuance of interest on its senior notes that were cancelled as part of its Chapter 11 Cases.

Reorganization Items

We incurred reorganization gain of $908.5 million for the seven months ended July 31, 2017 (Predecessor). The Predecessor gain resulted from the gain on the discharge of debt and fresh-start adjustments upon emergence from chapter 11 bankruptcy. See Note 3,“Fresh-Start Accounting” to the consolidated financial statements for further details.

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.

As of September 30, 2017, our critical accounting policies, except for those related to the effects of our Chapter 11 Cases discussed in Note 1,“Summary of Significant Accounting Policies” to the consolidated financial statements, are consistent with those discussed in Note 1 of our consolidate financial statements contained in our Predecessor’s 2016 Annual Report.

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, income taxes, liabilities subject to compromise and estimated enterprise value and fair values of assets and liabilities under the provisions of ASC 852 fresh-start accounting. Actual results could differ from those estimates.

Liquidity and Capital Resources

Overview

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

Statements of Cash Flows

The following table summarizes our primary sources and uses of cash in each of the most recent three years (in thousands):



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Net cash provided by operating activities	$	13,728		$	52,288		$	179,577
Net cash (used in) provided by investing activities	$	(23,444	)	$	76,836		$	219,535
Net cash used in financing activities	$	(1,129	)	$	(151,471	)	$	(360,318	)

Cash Flow from Operations

Net cash provided by operating activities was approximately $13.7 million and $52.3 million for the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, compared to cash provided by operating activities of approximately $179.6 million for the nine months ended September 30, 2016. The decrease was primarily due to the decrease in accounts receivable related to the timing of receipts from production and the decrease in other assets substantially related to prepaid drilling costs actually spent during the period. The decrease was offset by the net increase 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. The change in the fair value of our derivative contracts are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the related periods.

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 and acquisitions, respectively, as well as the prices received for production. We have historically entered into derivative contracts to reduce the impact of commodity price volatility on operations. During 2016 and part of 2017, we primarily used fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. See Note 6, “Price and Interest Rate Risk Management Activities” to the consolidated financial statements and Part I—Item 3—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk, for further discussion.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $23.4 million for the two months ended September 30, 2017 (Successor) and net cash provided by investing activities was approximately $76.8 million for the seven months ended July 31, 2017 (Predecessor), respectively, compared to cash provided by operating activities of approximately $219.5 million for the nine months ended September 30, 2016. The primary source of net cash provided by investing activities was the $126.4 million in proceeds from the sale of oil and natural gas properties for the seven months ended July 31, 2017 (Predecessor) offset by $23.7 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties and $25.7 million for additions to our oil and natural gas properties.

During the two months ended September 30, 2017 (Successor), we spent $9.0 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties and $14.4 million for additions to our oil and natural gas properties.

Net cash provided by investing activities during the first nine months of 2016 primarily included $288.5 million in proceeds from the sale of oil and natural gas properties. During the first nine months of 2016 cash used in investing activities included $49.1 million for the drilling and development of oil and natural gas properties, $7.5 million for the acquisition of a 51% joint venture interest in the Potato Hills Gas Gathering System, and $12.3 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $1.1 million and $151.5 million for the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, compared to cash used in financing activities of approximately $360.3 million for the nine months ended September 30, 2016.

During the two months ended September 30, 2017 (Successor), cash used in financing obligation primarily included payment of debt under the lease financing obligation. The primary drivers of net cash used in financing activities for the seven months ended July 31, 2017 (Predecessor) were repayments of debt of approximately $41.6 million under the Predecessor Credit Facility, repayment of debt of $500.3 million under the Predecessor Credit Facility in accordance with the Plan and payment for debt financing costs of $9.4 million. In addition, net cash provided by financing activities included $275.0 million for proceeds from rights offerings and second lien investment and $125.0 million for proceeds from the Successor Term Loan.

Net cash used in financing activities during the nine months ended September 30, 2016 included $337.4 million in net repayments of our long-term debt and $18.6 million cash paid to preferred, common and Class B unitholders in the form of distributions.

Debt and Credit Facilities

Successor Credit Facility

On the Effective Date, VNG, as borrower, has entered into that certain Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Successor Credit Facility”), by and among VNG as borrower, Citibank, N.A. as administrative agent (the “Administrative Agent”) and Issuing Bank, and the lenders party thereto (the “Lenders”). Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with an $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loans”). The initial borrowing base available under the Successor Credit Facility as of the Effective Date is $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date is $730.0 million. The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). The next borrowing base redetermination is scheduled for August of 2018.

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

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

New Second Lien Notes Indenture

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of new 9.0% Senior Secured Second Lien Notes due 2024 (the “New Notes”) to certain eligible holders of their outstanding Old Second Lien Notes issued by the Predecessor and the Successor (the “Existing Notes”) in full satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The New Notes were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

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



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

Amended and Restated Intercreditor Agreement

Amended and Restated Collateral Trust Agreement

Letters of Credit

Predecessor’s Credit Facility, Old Second Lien Notes and Senior Notes

On the Effective Date, pursuant to the terms of the Final Plan, all outstanding obligations under the Predecessor Credit Facility, Old Second Lien Notes and unsecured senior notes were canceled. See Note 2, “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” to the consolidated financial statements for additional information.

Lease Financing Obligations

2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

Off-Balance Sheet Arrangements

At September 30, 2017, we did not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial position or results of operations.

Contingencies

We regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Commitments and Contractual Obligations

A summary of our contractual obligations as of September 30, 2017 is provided in the following table (in thousands):



	Payments Due by Year
	2017		2018		2019		2020		2021		After 2021		Total
Management base salaries	$	403	$	1,670	$	510	$	510	$	—	$	—	$	3,093
Asset retirement obligations ⁽¹⁾	2,798		4,879		5,122		5,379		5,647		122,711		146,536
Derivative liabilities	9,980		29,546		12,034		7,012		—		—		58,572
Reserve-Based Credit Facility ⁽²⁾	—		—		—		—		730,000		—		730,000
Term Loan⁽²⁾	—		1,250		1,250		1,250		121,250		—		125,000
Senior Notes due 2024 and interest	—		7,265		7,265		7,265		7,265		97,654		126,714
Operating leases	318		1,202		1,149		1,136		1,169		5,707		10,681
Development commitments ⁽³⁾	24,487		—		—		—		—		—		24,487
Firm transportation agreements ⁽⁴⁾	356		1,009		821		410		—		—		2,596
Lease financing obligations ⁽⁵⁾	2,268		5,442		5,442		4,359		1,278		—		18,789
Other future obligations	117		468		308		—		—		—		893
Total	$	40,727	$	52,731	$	33,901	$	27,321	$	866,609	$	226,072	$	1,247,361


(1)	Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Please read Note 8, “Asset Retirement Obligations” to the consolidated financial statements for additional information regarding our asset retirement obligations.


(2)	This table does not include interest to be paid on the principal balances shown as the interest rates on our financing arrangements are variable.


(3)	Represents authorized expenditures for drilling, completion and major workover projects.


(4)	Represents transportation demand charges. Please read Note 9, “Commitments and Contingencies” to the consolidated financial statements for additional information regarding our firm transportation agreements.


(5)	The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments. The amounts presented include interest payable for each year.

Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard stockholders/unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard stockholders/unitholders plus:


•	Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:


•	Net interest expense;


•	Depreciation, depletion, amortization, and accretion;


•	Impairment of oil and natural gas properties;


•	Impairment of goodwill;


•	Net gains or losses on commodity derivative contracts;


•	Cash settlements on matured commodity derivative contracts;


•	Net gains or losses on interest rate derivative contracts;


•	Gain on extinguishment of debt;


•	Net gains or losses on acquisitions of oil and gas properties;


•	Taxes;


•	Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers;


•	Reorganization items;


•	Transaction costs incurred on reorganization, acquisitions, mergers and divestitures; and


•	Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard stockholders/unitholders.

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

Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Successor Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our consolidated statements of cash flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our consolidated statements of cash flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows which may increase or decrease the amount we have available to fund distributions.

As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way

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

Adjusted EBITDA attributable to Vanguard stockholders/unitholders for the two months ended September 30, 2017 (Successor) and the one month ended July 31, 2017 (Predecessor) were $30.9 million and negative $0.2 million, respectively, compared to $100.4 million for the three months ended September 30, 2016 (Predecessor). The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA (in thousands):



	Successor			Predecessor
	Two Months			One Month			Three Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Net income (loss) attributable to Vanguard stockholders/ unitholders	$	(37,297	)	$	963,089		$	(245,395	)
Add: Net income attributable to non-controlling interests	61			1			27
Net income (loss)	$	(37,236	)	$	963,090		$	(245,368	)
Plus:
Interest expense	9,615			5,003			22,976
Depreciation, depletion, amortization, and accretion	27,578			7,328			32,096
Impairment of goodwill	—			—			252,676
Change in fair value of commodity derivative contracts ^(a)	30,026			12,019			30,135
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period ^(a)	—			—			833
Fair value of derivative contracts acquired that apply to contracts settled during the period ^(a)	—			—			3,561
Net gains on interest rate derivative contracts ^(b)	—			—			(764		)
Net loss on acquisition of oil and natural gas properties	—			—			2,117
Taxes	—			158			(571		)
Compensation related items	—			711			2,746
Reorganization items	—			(988,452		)	—
Transaction costs incurred on reorganization, acquisitions, mergers and divestitures	903			—			75
Adjusted EBITDA before non-controlling interest	30,886			(143		)	100,512
Adjusted EBITDA attributable to non-controlling interest	(24		)	(39		)	(115		)
Adjusted EBITDA attributable to Vanguard stockholders/ unitholders	$	30,862		$	(182	)	$	100,397


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



	Successor			Predecessor
	Two Months			One Month			Three Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Net cash settlements received (paid) on matured commodity derivative contracts	$	(2,326	)	$	—		$	55,628
Change in fair value of commodity derivative contracts	(30,026		)	(12,019		)	(30,135		)
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period	—			—			(833		)
Fair value of derivative contracts acquired that apply to contracts settled during the period	—			—			(3,561		)
Net gain (losses) on commodity derivative contracts	$	(32,352	)	$	(12,019	)	$	21,099


(b)	Net gains on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:



	Predecessor
	Three Months
	Ended
	September 30, 2016
Cash settlements paid on interest rate derivative contracts	$	(2,043	)
Change in fair value of interest rate derivative contracts	2,807
Net gains on interest rate derivative contracts	$	764

Adjusted EBITDA attributable to Vanguard stockholders/unitholders for the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor) were $30.9 million and $115.2 million, respectively, compared to from $299.9 million for the nine months ended September 30, 2016. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA (in thousands) for the two months ended September 30, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor):



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Net income (loss) attributable to Vanguard stockholders/ unitholders	$	(37,297	)	$	900,298		$	(651,467	)
Add: Net income attributable to non-controlling interests	61			13			91
Net income (loss)	$	(37,236	)	$	900,311		$	(651,376	)
Plus:
Interest expense	9,615			35,276			72,612
Depreciation, depletion, amortization, and accretion	27,578			58,384			118,935
Impairment of oil and natural gas properties	—			—			365,658
Impairment of goodwill	—			—			252,676
Change in fair value of commodity derivative contracts ^(a)	30,026			24,894			201,388
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period ^(a)	—			—			2,532
Fair value of derivative contracts acquired that apply to contracts settled during the period ^(a)	—			—			9,936
Net (gains) losses on interest rate derivative contracts ^(b)	—			(30		)	6,061
Gain on extinguishment of debt	—			—			(89,714		)
Net loss on acquisition of oil and natural gas properties	—			—			3,782
Taxes	—			(634		)	(3,205		)
Compensation related items	—			5,797			7,721
Reorganization items	—			(908,485		)	—
Transaction costs incurred on reorganization, acquisitions, mergers and divestitures	903			—			3,198
Adjusted EBITDA before non-controlling interest	30,886			115,513			300,204
Adjusted EBITDA attributable to non-controlling interest	(24		)	(271		)	(347		)
Adjusted EBITDA attributable to Vanguard stockholders/ unitholders	$	30,862		$	115,242		$	299,857


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



	Successor			Predecessor
	Two Months			Seven Months			Nine Months
	Ended			Ended			Ended
	September 30, 2017			July 31, 2017			September 30, 2016
Net cash settlements received (paid) on matured commodity derivative contracts	$	(2,326	)	7			$	198,104
Change in fair value of commodity derivative contracts	(30,026		)	(24,894		)	(201,388		)
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period	—			—			(2,532		)
Fair value of derivative contracts acquired that apply to contracts settled during the period	—			—			(9,936		)
Net losses on commodity derivative contracts	$	(32,352	)	$	(24,887	)	$	(15,752	)


(b)	Net gains (losses) on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:



	Predecessor			Predecessor
	Seven Months			Nine Months
	Ended			Ended
	July 31, 2017			September 30, 2016
Cash settlements paid on interest rate derivative contracts	$	(95	)	$	(6,770	)
Change in fair value of interest rate derivative contracts	125			709
Net gains (losses) on interest rate derivative contracts	$	30		$	(6,061	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGLs prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Conditions sometimes arise where actual production is less than estimated, which has, and could result in over-hedged volumes. For a detailed discussion of the risk factors that relate to our potential exposure to market risks, please refer to Part I—Item 1A—Risk Factors in our Predecessor’s 2016 Annual Report on Form 10-K.

Commodity Price Risk

Our primary market risk exposure is in the prices we receive for our oil, natural gas and NGLs production. Realized pricing is primarily driven by prevailing spot market prices at our primary sales points and the applicable index prices. Pricing for oil, natural gas and NGLs production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control. In addition, the potential exists that if commodity prices decline to a certain level, the borrowing base for our Successor Credit Facility can be decreased at the borrowing base redetermination date to an amount lower than the amount of debt currently outstanding and, because it would be uneconomical, production could decline to levels below our hedged volumes. Furthermore, the risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future development costs increase.

We routinely enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that mitigate the volatility of future prices received as follows:


•	Fixed-price swaps - where we will receive a fixed-price for our production and pay a variable market price to the contract counterparty.


•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.

In deciding which type of derivative instrument to use, our management considers the relative benefit of each type against any cost that would be incurred, prevailing commodity market conditions and management’s view on future commodity pricing. The amount of oil and natural gas production which is hedged is determined by applying a percentage to the expected amount of production in our most current reserve report in a given year. Typically, management intends to hedge 75% to 90% of projected oil and natural gas production from proved developed producing reserves up to a three to four year period. These activities are intended to support our realized commodity prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. We have also entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. However, a liquid, readily available and commercially viable market for hedging NGLs has not developed in the same way that exists for crude oil and natural gas. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our NGL production effectively or at all. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Management will consider liquidating a derivative contract, if they believe that they can take advantage of an unusual market condition allowing them to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

In October and December 2016, our Predecessor monetized substantially all of our outstanding price commodity and interest rate hedges for total proceeds of approximately $54.0 million. Our Predecessor used the net proceeds from the hedge settlements to make deficiency payments under the Predecessor Credit Facility. In June 2017, we entered into derivative contracts primarily with counterparties that are also lenders under our Successor Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production, commencing with August 2017 production volumes.

At September 30, 2017, the fair value of commodity derivative contracts was a liability of approximately $54.9 million, of which $29.3 million settles during the next twelve months.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at September 30, 2017.



	October 1 -December 31, 2017		Year 2018		Year 2019		Year 2020
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu)	18,400,000		70,242,000		52,539,000		47,227,500
Fixed Price ($/MMBtu)	$	3.11	$	3.00	$	2.79	$	2.75
Collars:
Notional Volume (MMBtu)	—		—		4,125,000		5,490,000
Floor Price ($/MMBtu)	$	—	$	—	$	2.60	$	2.60
Ceiling Price ($/MMBtu)	$	—	$	—	$	3.00	$	3.00



	October 1 -December 31, 2017		Year 2018		Year 2019		Year 2020
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls)	818,900		3,059,200		1,858,200		1,393,800
Fixed Price ($/Bbl)	$	45.20	$	46.47	$	48.50	$	49.53
Collars:
Notional Volume (Bbls)	—		—		575,730		659,340
Floor Price ($/Bbl)	$	—	$	—	$	43.81	$	44.17
Ceiling Price ($/Bbl)	$	—	$	—	$	54.04	$	55.00



	October 1 -December 31, 2017		Year 2018
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Ethane
Notional Volume (Gallons)	2,704,800		9,198,000
Fixed Price ($/Gallon)	$	0.25	$	0.28
Mont Belvieu Propane
Notional Volume (Gallons)	6,182,400		22,995,000
Fixed Price ($/Bbl)	$	0.58	$	0.53
Mont Belvieu N. Butane
Notional Volume (Gallons)	2,318,400		7,665,000
Fixed Price ($/Gallon)	$	0.70	$	0.65
Mont Belvieu Isobutane
Notional Volume (Gallons)	1,545,600		6,132,000
Fixed Price ($/Gallon)	$	0.70	$	0.65
Mont Belvieu N. Gasoline
Notional Volume (Gallons)	3,091,200		10,731,000
Fixed Price ($/Gallon)	$	0.98	$	0.99

Interest Rate Risks

At September 30, 2017, we had debt outstanding of $942.9 million. The amount outstanding under our Successor Credit Facility at September 30, 2017 was approximately $855.0 million and is subject to interest at floating rates based on LIBOR. If the debt remains the same, a 10% increase in LIBOR would result in an estimated $1.1 million increase in annual interest expense.

Historically, we entered into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company recorded changes in the fair value of its interest rate derivatives in current earnings under net gains or losses on interest rate derivative contracts. At September 30, 2017, the Company had no outstanding interest rate hedge agreements.

Counterparty Risk

At September 30, 2017, based upon all of our open derivative contracts shown above and their respective mark to market values, we had the following current and long-term derivative liabilities shown by counterparty with their current Standard & Poor’s financial strength rating in parentheses (in thousands):



	Current Assets		Long-Term Assets		Current Liabilities			Long-Term Liabilities			Total Amount Due From/(Owed To) Counterparty at September 30, 2017
ABN AMRO (A)	$	—	$	—	$	(20,777	)	$	(8,155	)	$	(28,932	)
Capital One (BBB+)	254		—		—			(2,212		)	(1,958		)
Citibank (A+)	—		—		(6,522		)	(5,335		)	(11,857		)
Huntington Bank (BBB+)	—		—		(1,475		)	(4,466		)	(5,941		)
JP Morgan (A-)	—		—		(732		)	(5,501		)	(6,233		)
Total	$	254	$	—	$	(29,506	)	$	(25,669	)	$	(54,921	)

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

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 September 30, 2017 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the third quarter of 2017 we added internal control processes over financial reporting as a result of the following:


•	Application of fresh start accounting,


•	Transition from the full cost method of accounting to the successful efforts method of accounting for our natural gas and oil properties,


•	Adoption of the new revenue recognition standard (ASC 606), and


•	Corporate taxes due to Vanguard’s new C-corp structure.

Other than the those listed above, there were no changes in our internal control over financial reporting that occurred during the third quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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 Predecessor’s 2016 Annual Report on Form 10-K. There have been no material changes to the risk factors set forth in our Predecessor’s 2016 Annual Report on Form 10-K, 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 Final Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the

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

In addition, upon our emergence from bankruptcy, we adopted 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 our Predecessor’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our Common Stock.

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 Final Plan, the composition of our Board changed significantly. Upon emergence, our Board consisted of six directors, only one of whom, Scott W. Smith, our President and Chief Executive Officer, previously served on the Board of Directors of our Predecessor. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Predecessor’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.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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



Exhibit Number		Description of Exhibit
2.1		Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 2.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
3.1		Amended and Restated Certificate of Incorporation of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.2		Amended and Restated Bylaws of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.3		Certificate of Amendment as filed with the Delaware Secretary of State (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed September 29, 2017)
4.1		Amended and Restated Indenture, dated as of August 1, 2017, among Vanguard Natural Resources, Inc., the guarantors named therein and Delaware Trust Company, as trustee and collateral trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.1		Fourth Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Vanguard Natural Gas, LLC, Citibank N.A., as Administrative Agent and the financial institutions thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.2		Amended and Restated First Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.3		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.4		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among certain subsidiaries and affiliates of Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.5		Amended and Restated Intercreditor Agreement, dated as of August 1, 2017, by and among Citibank, N.A., as priority lien agent, and Delaware Trust Company, as second lien collateral trustee, and acknowledged and agreed to by Vanguard Natural Gas, LLC, Vanguard Natural Resources, Inc. and the other grantors party thereto (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.6		Amended and Restated Collateral Trust Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., the grantors and guarantors named therein and Delaware Trust Company as trustee and as collateral trustee (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.7		Registration Rights Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc. and certain parties thereto (incorporated by reference to Exhibit 10.7 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.8		Warrant Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc., as Issuer, and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.9		Second Amended and Restated Employment Agreement of Scott W. Smith, dated August 1, 2017 (incorporated by reference to Exhibit 10.9 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.10		Second Amended and Restated Employment Agreement of Richard A. Robert, dated August 1, 2017 (incorporated by reference to Exhibit 10.9 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.11		Second Amended and Restated Employment Agreement of Britt Pence, dated August 1, 2017 (incorporated by reference to Exhibit 10.11 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.12		Letter to Richard Scott Sloan, dated September 29, 2017 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed September 29, 2017)
10.13*		Vanguard Natural Resources, Inc. Management Incentive Plan
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
99.1		Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 99.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document

_______________


*	Provided herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		VANGUARD NATURAL RESOURCES, INC.
		(Registrant)

	Date: November 9, 2017	/s/ R. Scott Sloan
		R. Scott Sloan
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

Vanguard Natural Resources, Inc. - FORM 10-Q - November 9, 2017

Attached files

Vanguard Natural Resources, Inc. Reports