Vanguard Natural Resources, Inc. - FORM 10-Q

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

Attached files

Attached files

Vanguard Natural Resources, Inc. Reports

file	filename
EX-10.4 - EXHIBIT 10.4 - Vanguard Natural Resources, Inc.	ex104oxy-vanguardleasehold.htm
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	vnr2017q210-qexhibit32x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	vnr2017q210-qexhibit32x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	vnr2017q210-qexhibit31x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	vnr2017q210-qexhibit31x1.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 June 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.

(Successor in interest to Vanguard Natural Resources, LLC)

(Exact Name of Registrant as Specified in Its Charter)



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



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

(832) 327-2255

(Registrant’s Telephone Number, Including Area Code)

Vanguard Natural Resources, LLC

(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	☑	Accelerated filer
o	Non-accelerated filer	o	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 August 1, 2017, the registrant had 20,055,694 outstanding shares of common stock, $0.001 par value

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

TABLE OF CONTENTS



		Page

PART I – FINANCIAL INFORMATION
Item 1.	Unaudited Consolidated Financial Statements
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Members’ Deficit	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	65

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 3.	Defaults Upon Senior Securities	67
Item 4.	Mine Safety Disclosures	68
Item 5.	Other Information	68
Item 6.	Exhibits	69

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 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 “Reorganized Vanguard” or “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”), Encore Clear Fork Pipeline LLC (“ECFP”), 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 “Old Vanguard” and “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.vnrllc.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, natural gas liquids (“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

(as successor-in-interest to Vanguard Natural Resources, LLC (Debtor-in-Possession))

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Revenues:
Oil sales	$	41,046		$	49,941		$	85,676		$	85,595
Natural gas sales	51,712			32,431			109,175			69,302
NGLs sales	14,109			11,104			30,773			20,019
Net losses on commodity derivative contracts	(12,875		)	(68,610		)	(12,868		)	(36,851		)
Total revenues	93,992			24,866			212,756			138,065
Costs and expenses:
Production:
Lease operating expenses	36,823			38,515			75,305			80,842
Production and other taxes	9,138			9,476			19,203			18,144
Depreciation, depletion, amortization, and accretion	25,328			38,786			51,056			86,839
Impairment of oil and natural gas properties	—			157,894			—			365,658
Selling, general and administrative expenses	9,777			13,408			20,072			24,430
Total costs and expenses	81,066			258,079			165,636			575,913
Income (loss) from operations	12,926			(233,213		)	47,120			(437,848		)
Other income (expense):
Interest expense (excludes contractual interest expense of $8.6 million and $14.3 million for the three and six months ended June 30, 2017, respectively)	(13,832		)	(23,932		)	(30,273		)	(49,636		)
Net gains (losses) on interest rate derivative contracts	—			(2,135		)	30			(6,825		)
Net loss on acquisition of oil and natural gas properties	—			(1,665		)	—			(1,665		)
Gain on extinguishment of debt	—			—			—			89,714
Other	255			196			311			252
Total other income (expense), net	(13,577		)	(27,536		)	(29,932		)	31,840
Income (loss) before reorganization items	(651		)	(260,749		)	17,188			(406,008		)
Reorganization items (Note 2)	(53,221		)	—			(79,967		)	—
Net loss	$	(53,872	)	$	(260,749	)	$	(62,779	)	$	(406,008	)
Less: Net income (loss) attributable to non-controlling interests	5			(40		)	(12		)	(64		)
Net loss attributable to Vanguard unitholders	(53,867		)	(260,789		)	(62,791		)	(406,072		)
Distributions to Preferred unitholders	—			(6,689		)	(2,230		)	(13,379		)
Net loss attributable to Common and Class B unitholders	$	(53,867	)	$	(267,478	)	$	(65,021	)	$	(419,451	)

Net loss per Common and Class B unit – basic and diluted	$	(0.41	)	$	(2.04	)	$	(0.49	)	$	(3.20	)
Weighted average Common units outstanding
Common units – basic and diluted	130,961			131,015			130,959			130,772
Class B units – basic and diluted	420			420			420			420

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(as successor-in-interest to Vanguard Natural Resources, LLC (Debtor-in-Possession))

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(Unaudited)



	June 30, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	168,255		$	49,957
Trade accounts receivable, net	84,294			97,138
Other current assets	3,768			7,944
Total current assets	256,317			155,039
Oil and natural gas properties, at cost	4,647,438			4,725,692
Accumulated depletion, amortization and impairment	(3,910,989		)	(3,867,439		)
Oil and natural gas properties evaluated, net – full cost method	736,449			858,253
Other assets
Goodwill	253,370			253,370
Other assets	44,424			42,626
Total assets	$	1,290,560		$	1,309,288

Liabilities and members’ deficit
Current liabilities
Accounts payable:
Trade	$	3,841		$	12,929
Affiliates	—			1,443
Accrued liabilities:
Lease operating	13,505			14,909
Developmental capital	8,574			6,676
Interest	7,650			13,345
Production and other taxes	34,754			32,663
Other	17,421			5,416
Derivative liabilities	4,694			125
Oil and natural gas revenue payable	26,145			33,672
Long-term debt classified as current	1,319,157			1,753,345
Other current liabilities	14,382			14,160
Total current liabilities	1,450,123			1,888,683
Long-term debt, net of current portion (Note 4)	13,055			15,475
Derivative liabilities	8,181			—
Asset retirement obligations, net of current portion	261,013			264,552
Other long-term liabilities	39,050			39,443
Total liabilities not subject to compromise	1,771,422			2,208,153
Liabilities subject to compromise (Note 2)	476,268			—
Total liabilities	2,247,690			2,208,153
Commitments and contingencies (Note 8)
Members’ deficit (Note 9)
Cumulative Preferred units, 13,881,873 units issued and outstanding at June 30, 2017 and December 31, 2016	335,444			335,444
Common units, 130,978,907 units issued and outstanding at June 30, 2017 and 131,008,670 units at December 31, 2016	(1,306,809		)	(1,248,767		)
Class B units, 420,000 issued and outstanding at June 30, 2017 and December 31, 2016	7,615			7,615
Total VNR members’ deficit	(963,750		)	(905,708		)
Non-controlling interest in subsidiary	6,620			6,843
Total members’ deficit	(957,130		)	(898,865		)
Total liabilities and members’ deficit	$	1,290,560		$	1,309,288

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(as successor-in-interest to Vanguard Natural Resources, LLC (Debtor-in-Possession))

CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT

FOR THE SIX MONTHS ENDED JUNE 30, 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	$	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	$	335,444	$	(1,248,767	)	$	7,615	$	6,843		$	(898,865	)
Issuance costs related to prior period equity transactions	—		(16		)	—		—			(16		)
Unit-based compensation	—		4,765			—		—			4,765
Net income (loss)	—		(62,791		)	—		12			(62,779		)
Potato Hills cash distribution to non-controlling interest	—		—			—		(235		)	(235		)
Balance at June 30, 2017	$	335,444	$	(1,306,809	)	$	7,615	$	6,620		$	(957,130	)

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(as successor-in-interest to Vanguard Natural Resources, LLC (Debtor-in-Possession))

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)



	Six Months Ended
	June 30,
Operating activities	2017			2016
Net loss	$	(62,779	)	$	(406,008	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	51,056			86,839
Impairment of oil and natural gas properties	—			365,658
Amortization of deferred financing costs	2,228			2,348
Amortization of debt discount	348			1,783
Non-cash reorganization items	58,755			—
Compensation related items	4,765			6,103
Net losses on commodity and interest rate derivative contracts	12,838			43,676
Cash settlements received on matured commodity derivative contracts	7			142,476
Cash settlements paid on matured interest rate derivative contracts	(95		)	(4,727		)
Net loss on acquisition of oil and natural gas properties	—			1,665
Gain on extinguishment of debt	—			(89,714		)
Changes in operating assets and liabilities:
Trade accounts receivable	14,804			25,427
Other current assets	2,106			(96		)
Net premiums received (paid) on commodity derivative contracts	(16		)	905
Accounts payable and oil and natural gas revenue payable	(14,484		)	(40,220		)
Payable to affiliates	(890		)	(277		)
Accrued expenses and other current liabilities	5,564			(41,323		)
Other assets	(357		)	(2,965		)
Net cash provided by operating activities	73,850			91,550
Investing activities
Additions to property and equipment	(67		)	(36		)
Potato Hills Gas Gathering System acquisition	—			(7,470		)
Additions to oil and natural gas properties	(17,873		)	(28,009		)
Deposits and prepayments of oil and natural gas properties	(22,330		)	(5,342		)
Proceeds from the sale of oil and natural gas properties	107,689			285,590
Net cash provided by investing activities	67,419			244,733
Financing activities
Proceeds from long-term debt	—			93,500
Repayment of long-term debt	(22,683		)	(377,228		)
Distributions to Preferred unitholders	—			(6,690		)
Distributions to Common and Class B unitholders	—			(11,917		)
Potato Hills distribution to non-controlling interest	(235		)	(230		)
Financing fees	(53		)	(2,543		)
Net cash used in financing activities	(22,971		)	(305,108		)
Net increase cash and cash equivalents	118,298			31,175
Cash and cash equivalents, beginning of period	49,957			—
Cash and cash equivalents, end of period	$	168,255		$	31,175



Supplemental cash flow information:
Cash paid for interest	$	22,424	$	47,008
Non-cash investing activity:
Asset retirement obligations, net	$	7,890	$	10,045

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, INC. AND SUBSIDIARIES

(as successor-in-interest to Vanguard Natural Resources, LLC (Debtor-in-Possession))

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,” “Reorganized Vanguard” 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. 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 Reorganized Vanguard pursuant to the Plan (as defined below) 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 independent oil and gas company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Through our operating subsidiaries, as of June 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.

We were formed in October 2006 and completed our initial public offering in October 2007. Following the completion of the financial restructuring, the Company will have 20.1 million shares of its common stock outstanding. We expect that the Company’s shares of common stock and warrants will be traded and quoted on the OTCQX market (which is operated by OTC Markets Group, Inc.). The OTCQX market is an interdealer quotation system providing real time quotation services, each of which the Company believes constitutes an “established securities market” within the meaning of the Foreign Investment in Real Property Tax Act of 1980. The Company expects the new listing to go effective during the third quarter of 2017. Additionally, the Company is moving forward as a corporation for U.S. federal income tax purposes.

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 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 June 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 consolidated financial statements contained in our 2016 Annual Report.


(a)	Basis of Presentation and Principles of Consolidation

The consolidated financial statements as of June 30, 2017 and December 31, 2016 and for the three and six months ended June 30, 2017 and 2016 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 consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 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)	Chapter 11 Cases

On February 1, 2017 (the “Petition Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. Please read Note 2. Chapter 11 Cases for a discussion of the Chapter 11 Cases (as defined in Note 2).

For periods subsequent to filing the Bankruptcy Petitions (as defined in Note 2), we have prepared our consolidated financial statements in accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.


(c)	Oil and Natural Gas Properties

The full cost method of accounting is used to account for oil and natural gas properties. 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 as discussed below.

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 occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are 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. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge.

price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. No ceiling test impairment was required during the six months ended June 30, 2017.

When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.


(d)	Goodwill and Other Intangible Assets

We account for goodwill under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist.

In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) (ASU 2017-04) to simplify the accounting for goodwill impairment. The guidance eliminated the need for Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The new standard also eliminated the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. We elected to early adopt ASU 2017-04 for the quarter ended March 31, 2017. We did not record any goodwill impairment during the six months ended June 30, 2017 since the carrying value of our reporting unit was negative at June 30, 2017.


(e)	New Pronouncements Issued But Not Yet Adopted

In May 2014, the FASB issued 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. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein.

We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, other than additional disclosures, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation and begun contract review and documentation.

The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catch-up transition method). The Company is currently evaluating the available adoption methods.

In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", 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 on leases 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 May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16, pursuant to Staff Announcements at the March 3, 2016, EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU No. 2016-12). The amendments under this ASU provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective.

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. This ASU 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.


(f)	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 cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, 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. Actual results could differ from those estimates.


(g)	Prior Year Financial Statement Presentation

Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q.

2. Chapter 11 Cases

Commencement of Chapter 11 Cases

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.”

The subsidiary Debtors in the Chapter 11 Cases were the Successor; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUD II; ERAP; ERAP II; EAC; and EOC.

Reorganization Process

We operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. To assure ordinary course operations during the pendency of the Chapter 11 Cases, the Bankruptcy Court granted certain relief requested by the Debtors, including, among other things and subject to the terms and conditions of such orders, authorizing us to maintain our existing cash management system, to secure debtor-in-possession financing, to remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and to pay the prepetition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. This relief is designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. For goods and services provided following the Petition Date, we paid vendors in full under normal terms.

enjoined. This prohibited, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, all of our prepetition liabilities and obligations were settled or compromised under the Bankruptcy Code through our Chapter 11 Cases.

Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2016 Annual Report. These include risks and uncertainties arising as a result of our Chapter 11 Cases, and the number and nature of our outstanding Common Stock (as defined below) and shareholders, assets, liabilities, officers and directors could change materially because of our Chapter 11 cases. In addition, the descriptions of our prepetition operations, properties and capital plans included in this Quarterly Report on Form 10-Q may not accurately reflect our post-emergence operations, properties and capital plans.

Creditors’ Committees — Appointment & Formation

(a) Restructuring Support Parties

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 (the “Consenting 2020 Noteholders”) constituting at the time of signing approximately 52% of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”); (ii) certain holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders”) constituting at the time of signing approximately 10% of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the “Consenting Second Lien Noteholders” and, Consenting Senior Noteholders), constituting at the time of signing approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Old Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”).

On June 6, 2017, certain lenders under the Company’s Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”), among them Citibank, N.A., as administrative agent (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 (the “Amended RSA”).

(b) Official Unsecured Creditors Committee

On February 14, 2017, the Office of the United States Trustee appointed the Official Committee of Unsecured Creditors (the “Unsecured Creditors Committee”) pursuant to section 1102 of the Bankruptcy Code. The Unsecured Creditors Committee consists of the following three members: (i) UMB Bank, National Association, as Indenture Trustee; (ii) Wilmington Trust, National Association, as Indenture Trustee; and (iii) Encana Oil & Gas (USA), Inc.

On March 16, 2017, we filed a motion with the Bankruptcy Court disclosing a Stipulation and Agreed Order entered into on March 15, 2017, by and between the Debtors and certain unaffiliated holders of our Preferred Units and common units (the “Ad Hoc Equity Committee”) pursuant to which the Debtors and the Ad Hoc Equity Committee agreed, among other things, that professionals for the Ad Hoc Equity Committee would be funded by the Debtors’ estates for services performed within a defined scope and subject to agreed caps on fees and expenses as described in the Stipulation and Agreed Order.

Magnitude of Potential Claims

On March 16, 2017, the Debtors filed with the Bankruptcy Court Schedules and Statements, as defined below, setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The Schedules and Statements may be subject to further amendment or modification after filing. Certain holders of prepetition claims were required to file proofs of claim by their respective specified deadlines for filing certain proofs of claims in the Debtors’ Chapter 11 cases. Differences between amounts scheduled by the Debtors and claims by creditors have been and are being investigated and resolved through the claims resolution process. The claims resolution process continues after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Schedules and Statements — Claims & Claims Resolution Process

To the best of our knowledge, we notified all of our known current or potential creditors that the Debtors filed Chapter 11 cases. On March 16, 2017, each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors was a party, were subject to the qualifications and assumptions included therein, and were subject to amendment or modification over the course of the Chapter 11 Cases.

Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. In addition, there were variances between the amounts for certain claims listed in the Schedules and Statements and the amounts claimed by our creditors. Such variances, as well as other disputes and contingencies will be investigated and resolved through the claims resolution process in our Chapter 11 Cases.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wished to assert prepetition claims against us and whose claim (i) was not listed in the Schedules and Statements or (ii) was listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to April 30, 2017 for non-governmental creditors and July 31, 2017 for governmental creditors

As of July 31, 2017, approximately 1,040 claims totaling $19.5 billion have been filed with the Bankruptcy Court against the Debtors by approximately 800 claimants. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We expect the process of resolving claims filed against the Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with our Plan. As part of the process, we will work to resolve differences in amounts scheduled by the Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where necessary. Through the claims resolution process as set forth in the Plan, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have filed and will file objections with the Bankruptcy Court as necessary for the claims we believe should be disallowed. Claims that have been allowed or we believe are allowable are reflected in “Liabilities Subject to Compromise.”

As discussed above, the claims resolution process continues following our emergence from the Chapter 11 Cases. Accordingly, the ultimate number and amount of claims that will be allowed against the Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Restructuring Support Agreement

The Initial RSA and Amended RSA set forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”) to be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases. A summary of the restructuring transactions agreed to by the Restructuring Support Parties and to be effectuated through the Plan is included below. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Initial RSA and Amended RSA.

Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code

The Initial RSA contemplated the following Restructuring Transactions outlined below:

•

Allowed claims (“First Lien Claims”) under the Reserve-Based Credit Facility to be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and to be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims to participate in a new Company $1.1 billion reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by the same lenders under the Reserve-Based Credit Facility.


•	Allowed Second Lien Claims to receive new notes in the current principal amount of approximately $75.6 million, substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate.


•	Each holder of an allowed Senior Note Claim to receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering.


•	If the Plan was accepted by the classes of the general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units to receive their pro rata share of (a) 3% of the New Equity Interests and (b) three and a half year warrants for 3% of the New Equity Interests.


•	A $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims to execute a backstop commitment agreement to fully backstop the Senior Note Rights Offering.


•	The Second Lien Investors to purchase $19.3 million in New Equity Interests at a 25% discount to the Company’s total enterprise value.

The initial terms also provided for the establishment of a management incentive plan at the Company under which 10% of the New Equity Interests would have been reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities.

The initial RSA obligated the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan.

Second Amended Joint Plan of Reorganization

The following is a summary of the material terms of the Second Amended Joint Plan of Reorganization which was filed on May 31, 2017 and agreed to by the Restructuring Support Parties to the Amended RSA. This summary highlights only certain substantive provisions of this iteration of the Plan and is not intended to be a complete description of that iteration of the Plan. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Second Amended Joint Plan of Reorganization. The Second Amended Joint Plan of Reorganization provided for:

•

The Rights Offering, consisting of (i) a $10.2 million rights offering to be conducted in reliance upon the exemption from registration under the Securities Act provided in section 1145 of the Bankruptcy Code, pursuant to which Holders of Senior Notes Claims are entitled to purchase equity in Reorganized VNR Finance, (ii) a $117.7 million rights offering to be conducted in reliance upon the exemption from registration under the Securities Act provided in section 4(a)(2) of the Securities Act, pursuant to which Accredited Investor Eligible Holders of Senior Notes Claims are entitled to purchase equity in Reorganized VNR Finance, and (iii) a $127.9 million equity investment, pursuant to which the Commitment Parties will purchase equity in Reorganized VNR Finance. The Rights Offering Shares equal 84.8% of the New Common Stock, subject to dilution by the GUC Rights Offering, the New Management Incentive Plan, the New Common Stock issuable upon exercise of the New Warrants, and the New Common Stock issued to Encana;


•	A fully committed $19.3 million equity investment from the Second Lien Investors for shares of New Common Stock equal to 6.4% of the aggregate New Common Stock as of the Effective Date and subject to dilution as set forth in the Plan;

•

A full recovery for Holders of Allowed Lender Claims consisting of (i) cash in the amount of the Credit Agreement Interest plus (ii) cash in the amount of its Pro Rata share of the Glasscock Sale Proceeds. In addition, each such Holder shall receive treatment under either Option 1 or Option 2 below. If the Holder elects (or is deemed to elect, upon its execution of the Exit Facility Credit Agreement) Option 1 on its Ballot, it shall also receive its Option 1 Pro Rata Share of (i) the Lender Paydown, (ii) the Exit Revolving Loans, and (iii) the Exit Term A Loans. If such Holder elects Option 2 on its Ballot, it shall also receive its Option 2 Pro Rata Share of the Exit Term B Loans;


•	The issuance of new notes to Holders of Allowed Second Lien Notes Claims in an aggregate principal amount of approximately $78.1 million, plus accrued and unpaid post-petition interest through the Effective Date;


•	The GUC Rights Offering is in an amount equal to 21.9% of the total amount of all Allowed General Unsecured Claims and Allowed Encana Claims; provided that in no event shall the GUC Rights Offering Amount exceed (a) with respect to Holders of Allowed General Unsecured Claims, $7.7 million (such amount to be reduced, pro rata, for the

proportion of General Unsecured Claims for which an election to participate in the GUC Cash Pool was made) and (b) with respect to Encana, 21.9% of the amount of the Allowed Encana Claims (such amount to be reduced to reflect the same final rate, as a percentage of Allowed Claims, at which Holders of Allowed General Unsecured Claims electing to receive distributions from the GUC Equity Pool are able to subscribe for in the GUC Rights Offering in accordance with the GUC Rights Offering Procedures);

•

With respect to holders of VNR Preferred Units, on the Effective Date, except to the extent that a Holder of VNR Preferred Units agrees to less favorable treatment of its VNR Preferred Units, and subject to the terms of the Restructuring Transactions, all VNR Preferred Units shall be cancelled and shall be of no further force and effect, whether surrendered for cancellation or otherwise, and in full and final satisfaction, settlement, release, and discharge of and in exchange for each VNR Preferred Unit, each Holder of VNR Preferred Units shall receive: (a) if Class 6, Class 7, Class 8, Class 9, and Class 12 are each determined to have voted to accept the Plan in accordance with the Bankruptcy Code, such Holder’s Pro Rata share of (i) the VNR Preferred Unit Equity Distribution and (ii) VNR Preferred Unit New Warrants; or (b) if Class 6, Class 7, Class 8, Class 9, or Class 12 is determined to have voted to reject the Plan in accordance with the Bankruptcy Code, no distribution; provided that each Holder of VNR Preferred Units shall be given the opportunity to elect to waive its recovery, in which case the VNR Preferred Unit Equity Distribution and three year VNR Preferred Unit New Warrants that such Holder would have been entitled to receive shall be cancelled and of no further effect; and

•

With respect to holders of VNR Common Units, on the Effective Date, except to the extent that a Holder of VNR Common Units agrees to less favorable treatment of its VNR Common Units, and subject to the terms of the Restructuring Transactions, all VNR Common Units shall be cancelled and shall be of no further force and effect, whether surrendered for cancellation or otherwise, and in full and final satisfaction, settlement, release, and discharge of and in exchange for each VNR Common Unit, each Holder of VNR Common Units shall receive: (a) if Class 6, Class 7, Class 8, Class 9, Class 12, and Class 13 are each determined to have voted to accept the Plan in accordance with the Bankruptcy Code, such Holder’s Pro Rata share of three year VNR Common Unit New Warrants; or (b) if Class 6, Class 7, Class 8, Class 9, Class 12, or Class 13 is determined to have voted to reject the Plan in accordance with the Bankruptcy Code, no distribution; provided that each Holder of VNR Common Units shall be given the opportunity to elect to waive its recovery, in which case the VNR Common Unit New Warrants that such Holder would have been entitled to receive shall be cancelled and of no further effect.

Prior to the Effective Date, the Debtors were required to distribute waiver election forms to the Holders of VNR Preferred Units and VNR Common Units, pursuant to which the Holders elected to waive and decline any distribution on account of their VNR Preferred Units or VNR Common Units, as applicable. These waiver election forms set forth instructions for such Holders to either (i) electronically deliver their VNR Preferred Unit or VNR Common Unit positions through The Depository Trust Company's Automated Tender Offer Program (if the Holder held its VNR Preferred Units or VNR Common Units through a Nominee) or (ii) mark such election on the form and return the form to Prime Clerk LLC (if the VNR Preferred Units or VNR Common Units, as applicable, were held directly in the Holder’s name on the books and records of the stock transfer agent and not through a nominee).

The Amended RSA obligated the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan.

Modified Second Amended Joint Plan of Reorganization

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 long-term debt and annual interest payments of the reorganized Debtors.

The following is a summary of the material modifications of the Final Plan that were made to the Second Amended Joint of Plan of Reorganization described above. Capitalized terms used but not defined in this Report on Form 10-Q are defined in the Final Plan.


•	the issuance to holders of the Company’s Preferred Units of such holders’ pro rata share of (i) New Common Stock and (ii) three and a half year VNR Preferred Unit New Warrants to purchase additional shares of New Common Stock at a strike price of $44.25; and


•	the issuance to the Company’s common unitholders of such holders’ pro rata share of three and a half year VNR Common Unit New Warrants to purchase shares of New Common Stock at a strike price of $61.45, regardless of whether the holders of the Company’s common units voted to accept the Plan.

The warrant strike prices were calculated based on the Company’s plan equity value of $20.00 per share of New Common Stock, which the Bankruptcy Court confirmed as part of the Plan.

Unless otherwise specified, the treatment set forth in the Final Plan and Confirmation Order will be in full satisfaction of all claims against and equity interests in the Debtors, which will be discharged on the Effective Date. Other than assumed obligations, all of the Debtors’ prepetition claims and equity interests will be discharged by the Plan.

Additional information regarding the classification and treatment of claims and equity interests can be found in Article III of the Final Plan.

The Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017 as the Effective Date. The Company reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date. Pursuant to the Final Plan, each of the Company’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 canceled 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 reorganized parent’s new organizational documents authorize the company to issue new equity, certain of which was issued to holders of allowed claims pursuant to the Plan on the Effective Date. In addition, on the Effective Date, the Company entered into a registration rights agreement with certain equity holders. As of August 1, 2017, the Company had 20.1 million outstanding shares of common stock, $0.001 par value. (“Common Stock”).

Emergence from Chapter 11

On the Effective Date, the Debtors substantially consummated the Plan and emerged from their Chapter 11 Cases. As part of the transactions undertaken pursuant to the Plan, the Predecessor transferred all of its membership interests in Vanguard Natural Gas, LLC (“VNG”), a Kentucky limited liability company, 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. Following the end of the current fiscal year, we expect that the Predecessor will be dissolved. Following the completion of these transactions, the Company became the successor issuer to the Predecessor for purposes of and pursuant to Rule 15d-5 of the Exchange Act.

Prior to the consummation of the transactions undertaken pursuant to the Plan, the Company (as VNR Finance Corp.) was the co-issuer of the Predecessor’s debt securities and did not have any independent assets or operations. As described below, the Predecessor’s Senior Notes due 2020 and Senior Notes due 2019 were cancelled pursuant to the Plan. However, the Successor issued, and its subsidiaries guaranteed, new second lien notes due 2024 in the aggregate principal amount of $80.7 million in satisfaction of certain claims of the holders of the Old Second Lien Notes co-issued by the Predecessor and Successor.

Exit Facility

VNG, as borrower, has entered into that certain Fourth Amended and Restated Credit Agreement dated as of August 1, 2017 (the “Exit 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 Credit Agreement, the lenders party thereto agreed to provide VNG with $850.0 million exit senior secured reserve-based revolving credit facility (the “Revolving Loans”). The initial borrowing base available under the Credit Agreement as of the Effective Date is $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Credit Agreement as of the Effective Date is $850.0 million. The Credit Agreement 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.

based on the borrowing base utilization percentage under the Exit Facility or (ii) adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, based on the borrowing base utilization percentage under the Exit Facility.

Unused commitments under the Exit 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 Exit Facility). VNG may be required to make mandatory prepayments of the Revolving Loans in connection with certain borrowing base deficiencies.

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 Exit 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 Exit 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 Exit 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 Exit 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 Exit 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 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 1.00:1.00.

The Exit 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

million related to the Existing Notes held by such holders. The New Notes were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

The 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

Company’s revolving 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 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.

Registration Rights Agreement

On the Effective Date, in accordance with the 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 Plan (collectively, the “Registration Rights Holders”).

The Registration Rights Agreement requires 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.

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 Old Vanguard’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.

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, Richard A. Robert, 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.

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. Robert is entitled to an annual base salary of $490,000, which will increase to $510,000 on January 1, 2018; 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 of directors (the “Board”) has the discretion to increase the base salaries of Messrs. Smith, Robert 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”). Furthermore, within five (5) business days of the Effective Date, the Executives will receive quarterly bonuses that accrued from the quarter ended December 31, 2016 through the Effective Date, with the total bonus amounts payable to them being $609,636 for Mr. Smith, $464,272 for Mr. Robert, and $428,595 for Mr. Pence. 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, Robert 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, Robert 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.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The Bankruptcy Court entered an interim order approving the DIP Credit Agreement, which contained the following terms:


•	a revolving credit facility in the aggregate amount of up to $50.0 million, with $15.0 million available on an interim basis;

•

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

•

the maturity date of the DIP Credit Agreement was expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court had not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement;


•	interest will accrue at a rate per year equal to the LIBOR rate plus 5.5%;

•

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


•	the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents were entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases; subject to

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


•	the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and


•	the DIP Credit Agreement was subject to customary covenants, prepayment events, events of default and other provisions.

Throughout the pendency of the Chapter 11 Cases, the Company did not access funds through the DIP Credit Agreement.

Acceleration of Debt Obligations

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


•	$1.25 billion in unpaid principal and approximately $0.2 million of undrawn letters of credit, plus interest, fees, and other expenses arising under or in connection with the Reserve-Based Credit Facility.

•

$51.12 million in unpaid principal, plus interest, fees, and other expenses arising under or in connection with the Senior Notes due 2019 issued pursuant to that certain Indenture, dated as of May 27, 2011, as amended, by and among the Eagle Rock Energy Partners, L.P.; Eagle Rock Energy Finance Corp., the guarantors named therein, and U.S. Bank, National Association, as indenture trustee. VO became the issuer of the Senior Notes due 2019 pursuant to the Fourth Supplemental Indenture effective as of October 8, 2015, among VO, the Subsidiary Guarantors named therein, as guarantors and U.S. Bank, National Association. Wilmington Trust, National Association, became the successor indenture trustee to the Senior Notes due 2019 in connection with the Chapter 11 Cases.

•

$381.83 million in unpaid principal, plus interest, fees, and other expenses arising in connection with the Senior Notes due 2020 issued pursuant to that certain Indenture, dated as of April 4, 2012, among the Predecessor and Successor, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. UMB Bank, N.A., became the successor indenture trustee to the Senior Notes due 2020 in June 2016.

•

$75.63 million in unpaid principal, plus interest, fees, and other expenses arising in connection with the Second Lien Notes issued pursuant to that certain Indenture, dated as of February 10, 2016, among the Predecessor and Successor, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. The Delaware Trust Company is the successor indenture trustee to the Second Lien Notes.

Amounts outstanding under our prepetition Reserve-Based Credit Facility and Second Lien Secured Notes were not subject to compromise and have been reclassified as current liabilities in the consolidated balance sheet as of June 30, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. In addition, as discussed below, the unsecured obligations under our Senior Notes due 2020 and Senior Notes 2019 were included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures were subject to the applicable provisions of the Bankruptcy Code.

Liabilities Subject to Compromise

Liabilities subject to compromise represent estimates of known or potential prepetition claims expected to be resolved in connection with our Chapter 11 Cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to

compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Quarterly Report on Form 10-Q and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the Chapter 11 process, and we plan to make adjustments in future periods as necessary and appropriate. Such adjustments may be material.

Under the Bankruptcy Code, we had the right to assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. Rejections of contracts or leases, generally (1) were treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieved the Debtors of performing their future obligations under such contract or lease, and (3) entitled the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. Assumption of executory contracts or unexpired leases, generally required the Company to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty. Accordingly, any description of an executory contract or unexpired lease in this Quarterly Report on Form 10-Q, including any quantification of our obligations under any such contract or lease, is wholly qualified by the rejection rights we had under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto.

The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of June 30, 2017:



	June 30, 2017
	(in thousands)
Accounts payable	$	1,942
Accrued liabilities	30,639
Senior notes and accrued interest	443,687
Liabilities subject to compromise	$	476,268

Interest Expense

We have discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $14.3 million, representing interest expense from the Petition Date through June 30, 2017.

Reorganization Items

We use this category to reflect, where applicable, post-petition expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. The following table summarizes the components included in reorganization items on our consolidated statements of operations for six months ended June 30, 2017:



	Six Months Ended June 30, 2017
	(in thousands)
Professional and legal fees⁽¹⁾	$	34,808
Deferred financing costs and debt discount ⁽²⁾	16,444
Claims for non-performance of executory contracts ⁽³⁾	28,715
Total Reorganization items	$	79,967


(1)	Includes $13.6 million of accrued reorganization costs as of June 30, 2017 representing unpaid professional and legal fees directly related to the Chapter 11 Cases.


(2)	Includes a non-cash charge to write off the unamortized debt issuance costs and debt discounts of $16.4 million related to the Senior Notes due 2019 and Senior Notes due 2020 as these debt instruments were impacted by the bankruptcy reorganization process.


(3)	Includes accrued and unpaid amounts representing our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases.

Going Concern

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

3. Acquisitions and Divestitures

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 4), except for certain acquisitions, in which the Company issued units or exchanged assets as described below.

2017 Divestitures

On April 2017, we entered into a purchase and sale agreement, as amended, with a third party buyer for the sale of a substantial portion our oil and gas properties located in Glasscock County, Texas (the “Asset Sale”). The Asset Sale included the sale of leases with a purchase price of $96.9 million which we closed on May 19, 2017 and in a subsequent transaction on June 30, 2017, we closed the sale of wells related to the assets for an adjusted purchase price of $5.2 million, subject to customary post-closing adjustments. In accordance with the Final Plan as defined in Note 2, all net cash proceeds received from the Asset Sale were used to pay the lenders under the Reserve-Based Credit Facility on August 1, 2017, the Effective Date of the Final Plan.

During the six months ended June 30, 2017, we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $5.4 million. All cash proceeds received from the sales of these properties during the period were used to fund the Company’s operating and capital expenses as well as to cover the cost of the Chapter 11 Cases.

2016 Acquisitions and Divestitures

In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.9 million. As part of the acquisition, Vanguard also acquired the seller’s rights as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

In May 2016, we completed the sale of our natural gas, oil and natural gas liquids properties in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $270.5 million, subject to final post-closing adjustments (the “SCOOP/STACK Divestiture”). The Company used $268.4 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale.

During the year ended December 31, 2016, we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $28.2 million. All cash proceeds received from the sales of these properties were used to reduce borrowings under our Reserve-Based Credit Facility.

The SCOOP/STACK Divestiture and the sale of other oil and natural gas properties did not significantly alter the relationship between capitalized costs and proved reserves. As such, no gain or loss on sales of oil and natural gas properties were recognized and the sales proceeds were treated as an adjustment to the cost of the properties.

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the six months ended June 30, 2016 to show the effect on our consolidated results of operations as if the SCOOP/STACK Divestiture completed in 2016 had occurred on January 1, 2015.

The pro forma results reflect the elimination of the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture.

The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:



	Pro Forma
	Three Months Ended June 30, 2016			Six Months Ended June 30, 2016
	(in thousands, except per unit data)
Total revenues	$	67,655		$	215,426
Net loss attributable to Vanguard unitholders	$	(801,885	)	$	(931,913	)
Net loss per unit
Common and Class B units - basic and diluted	$	(9.29	)	$	(10.93	)

The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows:



	Pro Forma
	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
	(in thousands)
Revenues	$	7,386	$	17,542
Excess of revenues over direct operating expenses	$	6,222	$	15,278

4. Debt

Our financing arrangements consisted of the following as of the date indicated:



			Amount Outstanding
Description	Interest Rate	Maturity Date	June 30, 2017			December 31, 2016
			(in thousands)
Senior Secured Reserve-Based Credit Facility	Variable(1)	April 16, 2018	$	1,248,795		$	1,269,000
Senior Notes due 2019	8.375% (2)	June 1, 2019	51,120			51,120
Senior Notes due 2020	7.875% (3)	April 1, 2020	381,830			381,830
Senior Notes due 2023	7.00%	February 15, 2023	75,634			75,634
Lease Financing Obligation	4.16%	August 10, 2020 (4)	17,845			20,167
Unamortized discount on Senior Notes			—			(13,167		)
Unamortized deferred financing costs			(5,272		)	(11,072		)
Total debt			$	1,769,952		$	1,773,512
Less:
Long-term debt classified as current			(1,319,157		)	(1,753,345		)
Liabilities subject to compromise (Note 2)			(432,950		)	—
Current portion of Lease Financing Obligation			(4,790		)	(4,692		)
Total long-term debt			$	13,055		$	15,475


(1)	Variable interest rate was 3.59% and 3.11% at June 30, 2017 and December 31, 2016, respectively.


(2)	Effective interest rate was 21.45% at June 30, 2017 and December 31, 2016.


(3)	Effective interest rate was 8.00% at June 30, 2017 and December 31, 2016.


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

Acceleration of Debt Obligations

The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes, all of which we describe in further detail below. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures were stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under our prepetition Reserve-Based Credit Facility and Senior Secured Second Lien Notes have been reclassified as current liabilities in the consolidated balance sheet as of June 30, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. These amounts have not been classified as liabilities subject to compromise as we believe the values of the underlying assets provide sufficient collateral to satisfy such obligations. In addition, the unsecured obligations under our Senior Notes due in 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017.

We accelerated the amortization of the remaining debt issue discount of $12.8 million and debt issue costs of $3.6 million associated with the Senior Notes due 2019 and Senior Notes due 2020, fully amortizing those amounts as of the Petition Date. We entered into a restructuring agreement with the Lenders under our Reserve-Based Credit Facility, along with the Restructuring Support Agreement with certain holders of the Senior Secured Second Lien Notes, that was approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of the remaining debt issue costs related to the Reserve-Based Credit Facility and Senior Secured Second Lien Notes.

Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $14.3 million, representing interest expense from the Petition Date through June 30, 2017. We continue to accrue interest on the Reserve-Based Credit Facility and Senior Secured Second Lien Notes subsequent to the Petition Date since we anticipate such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. During the Chapter 11 Cases, we made interest payments under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest was paid to the holders of the Senior Secured Second Lien Notes subsequent to the Petition Date.

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

Senior Secured Reserve-Based Credit Facility

The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provided a maximum credit facility of $3.5 billion and a borrowing base of $1.1 billion (the “Reserve-Based Credit Facility”). As of June 30, 2017 there were approximately $1.2 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $148.9 million under the Reserve-Based Credit Facility.

The Reserve-Based Credit Facility was secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. Therefore, upon the acceleration as a consequence of the commencement of the Chapter 11 Cases, we reclassified the amount outstanding under our Reserve-Based Credit Facility to current portion of long-term debt, as the principal became immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions. Pursuant to the Final Plan, we entered into a new Company reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by the same lenders under the prepetition Reserve-Based Credit Facility.

Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Credit Agreement were canceled and discharged, and the Successor entered into the Exit Facility. See Note 2 for more information.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement included lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders.

Throughout the pendency of the Chapter 11 Cases, the Company did not access funds through the DIP Credit Agreement.

Letters of Credit

At June 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 Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with marketing counterparties.

8.375% Senior Notes Due 2019

At June 30, 2017, we had $51.1 million outstanding in aggregate principal amount of Senior Notes due 2019. The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger.

Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Senior Notes due 2019 were canceled and discharged. See Note 2 for more information.

7.875% Senior Notes Due 2020

At June 30, 2017, we had $381.8 million outstanding in aggregate principal amount of Senior Notes due 2020. The issuers of the Senior Notes due 2020 were the Predecessor and the prepetition Successor, which at the time had no independent assets or operations.

Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Senior Notes due 2020 were canceled and discharged. See Note 2 for more information.

7.0% Senior Secured Second Lien Notes Due 2023

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders.

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the six months ended June 30, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

Pursuant to the Plan, on the Effective Date, the Predecessor’s obligations with respect to the Old Second Lien Notes were canceled and discharged, and the Company issued the New Notes. See Note 2 for more information.

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.

5. Price and Interest Rate Risk Management Activities

In October and December 2016, we monetized substantially all of our commodity and interest rate hedge agreements for total proceeds of approximately $54.0 million. We used the net proceeds from the hedge settlements to make the deficiency payments under our Reserve-Based Credit Facility.

In June 2017, we entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in 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 Reserve-Based 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 following tables summarize oil, natural gas, and NGL commodity derivative contracts in place at June 30, 2017.

Fixed-Price Swaps (NYMEX)



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Bbls	Weighted Average Fixed Price
August 1, 2017 – December 31, 2017	22,950,000	$	3.12	1,365,100	$	45.20	627,300	$	26.42
January 1, 2018 – December 31, 2018	48,800,000	$	3.02	3,059,200	$	46.47	1,350,500	$	25.37
January 1, 2019 - December 31, 2019	20,637,500	$	2.86	821,250	$	47.42	—	$	—
January 1, 2020 - December 31, 2020	11,895,000	$	2.79	622,200	$	48.92	—	$	—

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	273,750	$	42.50	$	53.60
January 1, 2020 - December 31, 2020	5,490,000	$	2.60	$	3.00	219,600	$	42.50	$	56.10

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):



	June 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	$	4,122		$	(4,122	)	$	—
Total derivative instruments	$	4,122		$	(4,122	)	$	—

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	$	(16,997	)	$	4,122		$	(12,875	)
Total derivative instruments	$	(16,997	)	$	4,122		$	(12,875	)



	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 Reserve-Based Credit Facility (see Note 4. 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 $4.1 million at June 30, 2017. We minimize the credit risk related to derivative instruments by: (i) entering into derivative instruments with counterparties that our also lenders in our Reserve-Based 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 six months ended June 30, 2017 and the year ended December 31, 2016 are as follows:



	Six Months Ended June 30, 2017			Year Ended December 31, 2016
	(in thousands)
Derivative liability at beginning of period, net	$	(125	)	$	316,691
Purchases
Net premiums and fees received for derivative contracts	—			(2,444		)
Net losses on commodity and interest rate derivative contracts	(12,838		)	(46,939		)
Settlements
Cash settlements received on matured commodity derivative contracts	(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	$	(12,875	)	$	(125	)

6. 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 goodwill, 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.

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 represent their approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of June 30, 2017, the fair value of our Senior Notes due 2020 was estimated to be $11.5 million, our Senior Notes due 2019 was estimated to be $3.1 million and our Senior Secured Second Lien Notes was estimated to be $74.3 million. We consider the inputs to the valuation of our Senior Notes and our Senior Secured Second Lien Notes to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution.

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, 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):



	June 30, 2017
	Fair Value Measurements			Assets/Liabilities
	Using Level 2			at Fair Value
Liabilities:
Commodity price derivative contracts	$	(12,875	)	$	(12,875	)
Total derivative instruments	$	(12,875	)	$	(12,875	)



	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:



	Six Months Ended June 30, 2016
	(in thousands)
Unobservable inputs, beginning of period	$	(5,933	)
Total gains	6,922
Settlements	(3,225		)
Unobservable inputs, end of period	$	(2,236	)

Change in fair value included in earnings related to derivatives still held as of June 30,	$	589

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, other than the range bonus accumulators, 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.

We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize 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 7, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the six months ended June 30, 2017, in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.3 million, at fair value and also recorded a $0.03 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the six months ended June 30, 2017. During the year ended December 31, 2016, in connection with the new wells drilled, we incurred and recorded asset retirement obligations totaling $0.7 million, at fair value. In addition, we recorded a $1.3 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the year ended December 31, 2016. 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 ranging between 4.7% and 5.5%; and (4) the average inflation factor ranging between 1.8% and 2.0%. 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.

7. Asset Retirement Obligations

The asset retirement obligations as of June 30, 2017 and December 31, 2016 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2017 and the year ended December 31, 2016 were as follows:



	June 30, 2017			December 31, 2016
	(in thousands)
Asset retirement obligations, beginning of period	$	272,436		$	271,456
Liabilities added during the current period	299			713
Accretion expense	5,813			12,145
Retirements	(946		)	(2,230		)
Liabilities related to assets divested	(8,160		)	(10,915		)
Change in estimate	(29		)	1,267
Asset retirement obligation, end of period	269,413			272,436
Less: current obligations	(8,400		)	(7,884		)
Long-term asset retirement obligation, end of period	$	261,013		$	264,552

Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the six months ended June 30, 2017 and year ended December 31, 2016, the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $0.03 million and increased its estimates of future asset retirement obligations by $1.3 million, respectively, to reflect revised estimates to be incurred for plugging and abandonment costs.

8. Commitments and Contingencies

Transportation Demand Charges

As of June 30, 2017, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from four months 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 June 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.



	June 30, 2017
	(in thousands)
July 1, 2017 - December 31, 2017	$	760
2018	1,009
2019	820
2020	410
Total	$	2,999

As part of our Chapter 11 Cases, we rejected significant contracts for transportation via the Rockies Express Pipeline and the East Tennessee Natural Gas Pipeline. These rejected contracts total $24.9 million in gross future minimum transportation demand charges and are not included in the table above. We have accrued the amounts due to these parties of $20.0 million representing our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases. The accruals are reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017.

Legal Proceedings

We are defendants in certain legal proceedings arising in the normal course of our business. We are also a party to separate legal proceedings relating to (i) our merger with LRR Energy, L.P. (the “LRE Merger Litigation”), and (ii) our exchange (the Debt Exchange) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 4. Debt of the Notes to the Consolidated Financial Statements for further discussion). Since the filing of our 2016 Annual Report on Form 10-K, there have been no material developments with respect to the legal proceedings related to the Debt Exchange litigation.

With respect to the LRE Merger Litigation, the court in the LRE Merger Litigation has denied the defendants’ motion to dismiss and set the lawsuit for a one-week jury trial beginning on February 11, 2019. The parties are currently engaged in the pre-trial discovery process. For more information concerning the LRE Merger Litigation, please see our 2016 Annual Report on Form 10-K.

Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed as to the debtors, subject to reinstatement when either the Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 2. Chapter 11 Cases for information regarding our Chapter 11 Cases.

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.

9. Members’ Deficit and Net Loss per Common and Class B Unit

Effect of Filing on Unitholders

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units, Series C Preferred Units and Common and Class B Units are entitled to receive any distribution or retain any property under a plan of reorganization.

Our common units, Class B units and Preferred Units were accounted for at their carrying value through the Effective Date of the reorganization.

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2017 and December 31, 2016:



				June 30, 2017			December 31, 2016
	Earliest Redemption Date	Liquidation Preference Per Unit	Distribution Rate	Units Outstanding	Carrying Value (in thousands)		Units Outstanding	Carrying Value (in thousands)
Series A	June 15, 2023	$25.00	7.875%	2,581,873	$	62,200	2,581,873	$	62,200
Series B	April 15, 2024	$25.00	7.625%	7,000,000	$	169,265	7,000,000	$	169,265
Series C	October 15, 2024	$25.00	7.75%	4,300,000	$	103,979	4,300,000	$	103,979
Total Cumulative Preferred Units				13,881,873	$	335,444	13,881,873	$	335,444

On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. As a result of the Chapter 11 Cases, we stopped accruing dividends on Preferred Units as of the Petition date. As of June 30, 2017, dividends in arrears related to our Preferred Units were $5.1 million, $13.3 million and $8.3 million, respectively.

Pursuant to the Plan, on the Effective Date, the Preferred Units were canceled. See Note 2 for more information.

Common and Class B Units

The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.

The following is a summary of the changes in our common units issued during the six months ended June 30, 2017 and the year ended December 31, 2016 (in thousands):

There was no change in issued and outstanding Class B units during the six months ended June 30, 2017 or the year ended December 31, 2016.

Pursuant to the Plan, on the Effective Date, the common units and Class B units were canceled. See Note 2 for more information.

Net Loss per Common and Class B Unit

Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, by the weighted average number of units outstanding during the period. Diluted net income (loss) per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income (loss) per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income (loss) per unit.

For the three months ended June 30, 2017 and 2016, 13,472,608 and 2,633,333 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position. For the six

months ended June 30, 2017 and 2016, 13,562,608 and 2,633,333 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were also in a loss position.

Distributions Declared

The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented.

Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Preferred Units effective with the February 2016 distribution.



	Cash Distributions
Distribution	Per Unit		Declared Date	Record Date	Payment Date
2016
First Quarter
January	$	0.0300	February 18, 2016	March 1, 2016	March 15, 2016
2015
Fourth Quarter
December	$	0.0300	January 20, 2016	February 1, 2016	February 12, 2016

10. Unit-Based Compensation

Long-Term Incentive Plan

The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights.

Restricted and Phantom Units

A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee were able to grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units were outstanding.

The fair value of restricted unit and phantom unit awards was measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that were required to be settled in units were recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company had the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognized the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards was remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.

Executive Employment Agreements

On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “2016 Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The 2016 Agreements were effective January 1, 2016 and the initial term of the 2016 Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 and each successive January 1 thereafter, provided that neither VNRH nor the

executives deliver a timely non-renewal notice prior to a term expiration date.

The 2016 Agreements provide for the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As a result of the Chapter 11 Cases, the executive officers did not receive a payout of any compensation related to the performance-based cash bonus award in 2017. However, we recognized total compensation expense related to these arrangements of $0.5 million and $0.7 million for the three months ended June 30, 2017 and 2016, respectively, and $1.0 million and $1.2 million for the six months ended June 30, 2017 and 2016, respectively, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations. In addition, as of June 30, 2017, we recognized an accrued liability of $1.4 million for the unpaid performance-based cash bonus award including a $0.4 million accrual for the unpaid portion of the 2016 performance-based cash bonus award. The accrual is included in liabilities subject to compromise on the Consolidated Balance Sheets as of June 30, 2017.

Under the 2016 Agreements, the executives were also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Any restricted units and phantom units granted to executives under the 2016 Agreements are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units included tandem grant of DERs. Pursuant to the Final Plan, all unvested equity grants outstanding immediately before the Effective Date were canceled and are of no further force or effect as of the Effective Date.

Pursuant to the Plan, on the Effective Date, the Successor entered into the Amended and Restated Employment Agreements with Messrs. Smith, Robert and Pence. See Note 2 for more information.

Unit Grants

In January 2017, the executives were granted a total of 10,611,940 phantom units in accordance with the 2016 Agreements. Also, during the six months ended June 30, 2017, our three independent board members were granted a total of 480,768 phantom units which were intended to vest one year from the date of grant.

Restricted Units

A summary of the status of the non-vested restricted units as of June 30, 2017 is presented below:



	Number of Non-vested Restricted Units		Weighted Average Grant Date Fair Value
Non-vested restricted units at December 31, 2016	647,784		$	19.14
Forfeited	(11,958	)	$	17.69
Vested	(257,497	)	$	20.80
Non-vested restricted units at June 30, 2017	378,329		$	18.07

At June 30, 2017, there was approximately $2.4 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately less than a year. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $0.9 million and $1.4 million in the selling, general and administrative expenses line item for the three months ended June 30, 2017 and 2016, respectively, and $1.7 million and $2.6 million for the six months ended June 30, 2017 and 2016, respectively.

Phantom Units

A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2017 is presented below:



	Number of Non-vested Phantom Units		Weighted Average Grant Date Fair Value
Non-vested phantom units at December 31, 2016	3,628,529		$	2.96
Granted	11,092,708		$	0.67
Forfeited	(54,562	)	$	2.11
Vested	(956,830	)	$	4.31
Non-vested phantom units at June 30, 2017	13,709,845		$	1.02

At June 30, 2017, there were approximately $10.7 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.6 years. Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $1.6 million and $1.2 million in the selling, general and administrative expense line item for the three months ended June 30, 2017 and 2016, respectively, and $3.4 million and $2.4 million for the six months ended June 30, 2017 and 2016, respectively.

Effect of Emergence from Bankruptcy on Unit-Based Compensation

Pursuant to the Final Plan, all unvested equity grants outstanding immediately before the Effective Date were canceled and of no further force or effect as of the Effective Date. In addition, on the Effective Date, the VNR LTIP was canceled and extinguished, and participants in the VNR LTIP received no payment or other distribution on account of the VNR LTIP.

11. Shelf Registration Statements

Prior to the entry into the Chapter 11 Cases, the Company had an effective universal shelf registration statement on Form S-3, as amended (File No. 333-210329), filed with the SEC, under which the Company registered an indeterminate amount of common units, Preferred Units, debt securities and guarantees of debt securities. The Company also had on file with the SEC a post-effective shelf registration statement on Form S-3, as amended (File No. 333-207357), under which the Company registered up to 14,593,606 common units. Finally, the Company had previously registered an indeterminate amount of common units, Preferred Units, debt securities and guarantees of debt securities under a registration statement on Form S-3, as amended (File No. 333-202064). Following the Effective Date, the Company filed post-effective amendments to the shelf registration statements to deregister the securities.

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

The historical consolidated financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”) reflect all of the assets, liabilities and results of operations of Vanguard Natural Resources, Inc. and its consolidated subsidiaries. The following discussion analyzes the financial condition and results of operations of Vanguard for the six months ended June 30, 2017 and 2016. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Vanguard in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “2016 Annual Report”) and the historical unaudited consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

When referring to Vanguard Natural Resources, Inc. (formerly known as VNR Finance Corp. and also referred to as “Successor,” “Reorganized Vanguard” 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. 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 Reorganized Vanguard pursuant to the Plan (as defined below) on August 1, 2017 (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.

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 June 30, 2017, based on internal reserve estimates, our total estimated proved reserves were 1,390 Bcfe, of which approximately 66% were natural gas reserves, 18% were oil reserves and 16% were NGLs reserves. All of our estimated reserves were classified as proved developed. As of December 31, 2016, the Company removed all PUD reserves from its total proved reserve estimate due to uncertainty regarding the availability of capital that would be required to develop the PUD reserves. Also, at June 30, 2017, we owned working interests in 11,930 gross (4,337 net) productive wells. Our operated wells accounted for approximately 61% of our total estimated proved reserves at June 30, 2017. Our average net daily production for the six months ended June 30, 2017 and the year ended December 31, 2016 was 381 MMcfe/day and 433 MMcfe/day, respectively. We have interests in approximately 677,869 gross undeveloped leasehold acres surrounding our existing wells.

Bankruptcy Proceedings Under Chapter 11

Commencement of Chapter 11 Cases

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 being administered under the caption “In re Vanguard Natural Resources, LLC, et al.”

The subsidiary Debtors in the Chapter 11 Cases were the Successor; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUD II; ERAP; ERAP II; EAC; and EOC.

Reorganization Process

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

Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2016 Annual Report. These include risks and uncertainties arising as a result of our Chapter 11 Cases, and the number and nature of our outstanding Common Stock (as defined below) and shareholders, assets, liabilities, officers and directors could change materially because of our Chapter 11 Cases. In addition, the descriptions of our prepetition operations, properties and capital plans included in this Quarterly Report on Form 10-Q may not accurately reflect our post-emergence operations, properties and capital plans.

Creditors’ Committees - Appointment & Formation

(a) Restructuring Support Parties

(b) Official Unsecured Creditors Committee

Magnitude of Potential Claims

emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Schedules and Statements - Claims & Claims Resolution Process

To the best of our knowledge, we notified all of our known current or potential creditors that the Debtors filed Chapter 11 Cases. On March 16, 2017, each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors was a party, were subject to the qualifications and assumptions included therein, and were subject to amendment or modification over the course of the Chapter 11 Cases.

Restructuring Support Agreement

Amended RSA.

Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code

The Initial RSA contemplated the following Restructuring Transactions outlined below:

•


•	Allowed Second Lien Claims to receive new notes in the current principal amount of approximately $75.6 million, substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate.


•	Each holder of an allowed Senior Note Claim to receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering.


•	If the Plan was accepted by the classes of the general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units to receive their pro rata share of (a) 3% of the New Equity Interests and (b) three and a half year warrants for 3% of the New Equity Interests.


•	A $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims to execute a backstop commitment agreement to fully backstop the Senior Note Rights Offering.


•	The Second Lien Investors to purchase $19.3 million in New Equity Interests at a 25% discount to the Company’s total enterprise value.

Second Amended Joint Plan of Reorganization

•


•	A fully committed $19.3 million equity investment from the Second Lien Investors for shares of New Common Stock equal to 6.4% of the aggregate New Common Stock as of the Effective Date and subject to dilution as set forth in the Plan;

•


•	The issuance of new notes to Holders of Allowed Second Lien Notes Claims in an aggregate principal amount of approximately $78.1 million, plus accrued and unpaid post-petition interest through the Effective Date;

•

The GUC Rights Offering is in an amount equal to 21.9% of the total amount of all Allowed General Unsecured Claims and Allowed Encana Claims; provided that in no event shall the GUC Rights Offering Amount exceed (a) with respect to Holders of Allowed General Unsecured Claims, $7.7 million (such amount to be reduced, pro rata, for the proportion of General Unsecured Claims for which an election to participate in the GUC Cash Pool was made) and (b) with respect to Encana, 21.9% of the amount of the Allowed Encana Claims (such amount to be reduced to reflect the same final rate, as a percentage of Allowed Claims, at which Holders of Allowed General Unsecured Claims electing to receive distributions from the GUC Equity Pool are able to subscribe for in the GUC Rights Offering in accordance with the GUC Rights Offering Procedures);

•

Modified Second Amended Joint Plan of Reorganization


•	the issuance to holders of the Company’s Preferred Units of such holders’ pro rata share of (i) New Common Stock and (ii) three and a half year VNR Preferred Unit New Warrants to purchase additional shares of New Common Stock at a strike price of $44.25; and


•	the issuance to the Company’s common unitholders of such holders’ pro rata share of three and a half year VNR Common Unit New Warrants to purchase shares of New Common Stock at a strike price of $61.45, regardless of whether the holders of the Company’s common units voted to accept the Plan.

The warrant strike prices were calculated based on the Company’s plan equity value of $20.00 per share of New Common Stock, which the Bankruptcy Court confirmed as part of the Plan.

Additional information regarding the classification and treatment of claims and equity interests can be found in Article III of the Final Plan.

Emergence from Chapter 11

Exit Facility

The maturity date of the Exit 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 Exit Facility or (ii) adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, based on the borrowing base utilization percentage under the Exit Facility.

Unused commitments under the Exit 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

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 revolving 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 and certain other matters.

Amended and Restated Collateral Trust Agreement

Registration Rights Agreement

Warrant Agreement

Second Amended and Restated Employment Agreements

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

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement included lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The Bankruptcy Court entered an interim order approving the DIP Credit Agreement, which contained the following terms:


•	a revolving credit facility in the aggregate amount of up to $50.0 million, with $15.0 million available on an interim basis;

•

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

•

the maturity date of the DIP Credit Agreement was expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court had not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date was able to be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement;


•	interest accrued at a rate per year equal to the LIBOR rate plus 5.5%;

•

the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents were entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases; subject to limited exceptions provided for in the DIP Motion, and were secured by (i) a first priority, priming security interest

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


•	the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and


•	the DIP Credit Agreement was subject to customary covenants, prepayment events, events of default and other provisions.

Throughout the pendency of the Chapter 11 Cases, the Company did not access funds through the DIP Credit Agreement.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Company and the Chapter 11 Subsidiaries had the right to assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Rejection of an executory contract or unexpired lease was generally treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company and the Chapter 11 Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may have given rise to a prepetition general unsecured claim for damages caused by such deemed breach.

Chapter 11 Filing Impact on Creditors and Unitholders

For more information regarding the ultimate recovery to all creditors and/or unitholders, see “—Emergence from Chapter 11” above.

Reorganization Expenses

The Company and the Chapter 11 Subsidiaries have incurred and will continue to incur significant costs associated with the reorganization, principally professional fees. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations.

Recent Developments and Outlook

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. The prices of oil, natural gas and NGLs increased slowly during the six months ended June 30, 2017, following significant decreases during 2015 and most of 2016. The crude oil spot price per barrel during the years ended December 31, 2015 and 2016 ranged from a high of $61.36 to a low of $26.19 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $3.44 to a low of $1.49. NGLs prices also suffered similar volatility. However, the crude oil spot price per barrel during the first six months of 2017 ranged from a low of $42.48 to a high of $54.48 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a a low of $2.44 to a high of $3.71. As of July 31, 2017, the crude oil spot price per barrel was $50.21 and the NYMEX natural gas spot price per MMBtu was $2.87. Among the factors causing such volatility are the domestic and foreign supply of oil and natural gas, the ability of the OPEC members to comply with the agreed upon production cuts and the cooperation of other producing countries to reduce production levels, social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States and the level and growth of consumer product demand.

The overall decline in commodity prices in recent years has had a negative impact on the price of our common and preferred units and ultimately was a significant contributing factor to our filing for bankruptcy protection. During 2016, when our common units were listed on NASDAQ, our common unit price declined from a high of $3.11 on January 4, 2016 to a low of $0.50 on November 18, 2016. This low commodity price environment has had and will continue to have a direct impact on our revenue, cash flow from operations and Adjusted EBITDA until commodity prices improve and stabilize. Sustained low prices or any further declines in prices of oil, natural gas and NGLs could have a material adverse impact on our financial condition, profitability, future growth, and the carrying value of our oil and natural gas properties. Additionally, sustained low

prices or any further decline in prices of oil, natural gas and NGLs could reduce the amount of oil, natural gas and NGLs that we can produce economically, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and natural gas properties. To illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of June 30, 2017 would decrease from 1,390 Bcfe to 1,179 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices and oil prices were derived from the 5-year NYMEX forward strip price (using monthly NYMEX settlement prices through December 2022) at July 21, 2017, our total proved reserves as of June 30, 2017 would decrease from 1,390 Bcfe to 1,381 Bcfe. Below is a tabular presentation of the prices depicted in illustration (2) which differ from the SEC 12-month average pricing of $3.02 per MMBtu for natural gas and $48.88 per barrel of crude oil (held constant):



	2017	2018	2019	2020	2021	2022 ⁽¹⁾
Oil ($/Bbl)	$46.09	$47.35	$48.44	$49.61	$50.98	$52.32
Natural Gas ($/MMBtu)	$3.04	$3.00	$2.83	$2.79	$2.82	$2.85

(1) Prices for 2022 and subsequent years were not escalated and were held flat for the remaining lives of the properties. Capital and lease operating expenses were also not inflated and held constant for the remaining lives of the properties.

When comparing these settlement prices to the prices of $3.02 per MMBtu for natural gas and $48.88 per barrel of crude oil used to generate our June 30, 2017 (“2Q17”) reserve report, the average annual prices for oil presented above are lower than the 2Q17 reserve report price through 2018 and higher thereafter and the average annual prices for natural gas are higher than the 2Q17 reserve report price through the end of 2017, and lower thereafter. The impact of the changes in forward prices to gas wells and oil wells, as compared to the 2Q17 reserve report prices, includes (i) an increase in economically recoverable oil volumes, and (ii) even if such volumes did not increase, an increase in realized prices for oil. Because the Company’s asset mix is 66% natural gas paired with a higher rate of decrease in natural gas prices when compared to oil (specifically the year 2018 and forward), the hypothetical decrease in natural gas reserves was greater than the hypothetical increase in oil reserves on an MMcfe basis.

The following table compares the 2Q17 reserve report volumes by product with the strip pricing volumes:



	Net Oil (Bbls)	Net Gas (Mcf)	Net NGL (Bbls)	Net MMcfe
Reserve Report at 2Q17	41,713	919,428	36,699	1,390
July 21, 2017 NYMEX Strip Price	42,624	905,796	36,648	1,381
% Difference	2%	(1)%	—%	(1)%

Management believes that the use of the 5-year NYMEX forward strip price may help provide investors with an understanding of the impact of the currently expected commodity price environment to our proved reserves. However, the use of this 5-year NYMEX forward strip price is not necessarily indicative of management’s overall outlook on future commodity prices. We intend to improve our financial outlook through opportunistic hedging, and profitable drilling and development of new and existing oil and natural gas properties.

We did not have any write-downs of our oil and natural gas properties related to the full cost ceiling limitation during the three months ended June 30, 2017. Commodity prices declined slightly during the second quarter of 2017 and still remain volatile. Whether any further impairments will be necessary, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2017, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions or divestitures, which could increase, decrease or eliminate the need for such impairments.

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

We have implemented a hedging program for approximately 80%, 72%, 26% ,and 21% of our anticipated crude oil production in 2017, 2018, 2019, and 2020, respectively, with 100% in the form of fixed-price swaps in 2017. Approximately 56%, 46%, 22%, and 16% 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. NGLs production was under fixed-price swaps for approximately 43% and 37% of anticipated production in 2017 and 2018, respectively. These hedges will provide some cash flow certainty regardless of the volatility in commodity prices.

We currently anticipate a capital expenditures budget of approximately $116 million through the end of 2017. We spent $37.3 million during the six months ended June 30, 2017 and expect to spend approximately $78.7 million during the remainder of 2017. We expect to focus our 2017 capital in two main areas; Green River Pinedale and East Haynesville field. In the Green River Basin we will participate as a non-operated partner in the drilling and completion of vertical natural gas wells in Pinedale Field. In the Gulf Coast Basin East Haynesville Field, we have a rig drilling Haynesville and Smackover wells. Our capital expenditures budget for 2017 is dependent upon future commodity prices and is subject to change. During the six months ended June 30, 2017, we drilled four gross (3.8 net) operated wells. In addition we participated in the drilling of 91 gross (11.2 net) non-operated wells and in the completion of 54 gross (7.1 net) non-operated wells.

Results of Operations

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017 ^(a)			2016 ^(a)			2017 ^(a)			2016 ^(a)
Revenues:
Oil sales	$	41,046		$	49,941		$	85,676		$	85,595
Natural gas sales	51,712			32,431			109,175			69,302
NGLs sales	14,109			11,104			30,773			20,019
Oil, natural gas and NGLs sales	106,867			93,476			225,624			174,916
Net losses on commodity derivative contracts	(12,875		)	(68,610		)	(12,868		)	(36,851		)
Total revenues	93,992			24,866			212,756			138,065
Costs and expenses:
Production:
Lease operating expenses	36,823			38,515			75,305			80,842
Production and other taxes	9,138			9,476			19,203			18,144
Depreciation, depletion, amortization, and accretion	25,328			38,786			51,056			86,839
Impairment of oil and natural gas properties	—			157,894			—			365,658
Non-cash compensation	2,456			2,578			5,086			4,975
Other selling, general and administrative expenses	7,321			10,830			14,986			19,455
Total costs and expenses	$	81,066		$	258,079		$	165,636		$	575,913
Other income (expense):
Interest expense (excludes contractual interest expense of $8.6 million and $14.3 million for the three and six months ended June 30, 2017, respectively)	$	(13,832	)	$	(23,932	)	$	(30,273	)	$	(49,636	)
Net gains (losses) on interest rate derivative contracts	—			(2,135		)	30			(6,825		)
Net loss on acquisitions or divestitures of oil and natural gas properties	—			(1,665		)	—			(1,665		)
Gain on extinguishment of debt	—			—			—			89,714
Other	255			196			311			252
Reorganization items	(53,221		)	—			(79,967		)	—


(a)	During the three and six months ended June 30, 2017 and June 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.

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

Revenues

Oil, natural gas and NGLs sales increased $13.4 million to $106.9 million during the three months ended June 30, 2017 as compared to the same period in 2016. The key oil, natural gas and NGLs revenue measurements were as follows:



	Three Months Ended				Percentage Increase / (Decrease)
	June 30,
	2017 ^(a)		2016 ^(a)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	42.52	$	39.44	8	%
Natural Gas (Price/Mcf)	$	2.21	$	1.17	89	%
NGLs (Price/Bbl)	$	16.19	$	13.05	24	%
Average realized prices, including hedges^(b):
Oil (Price/Bbl)	$	42.52	$	55.90	(24	)%
Natural Gas (Price/Mcf)	$	2.21	$	2.89	(24	)%
NGLs (Price/Bbl)	$	16.19	$	14.22	14	%
Average NYMEX prices:
Oil (Price/Bbl)	$	48.31	$	45.54	6	%
Natural Gas (Price/Mcf)	$	3.18	$	1.95	63	%
Total production volumes:
Oil (MBbls)	965		1,266		(24	)%
Natural Gas (MMcf)	23,362		27,820		(16	)%
NGLs (MBbls)	871		851		2	%
Combined (MMcfe)	34,382		40,524		(15	)%
Average daily production volumes:
Oil (Bbls/day)	10,608		13,913		(24	)%
Natural Gas (Mcf/day)	256,729		305,716		(16	)%
NGLs (Bbls/day)	9,575		9,353		2	%
Combined (Mcfe/day)	377,822		445,314		(15	)%


(a)	During the three months ended June 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)	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 increase in oil, natural gas and NGLs sales during the three months ended June 30, 2017 compared to the same period in 2016 was due primarily to the increase in the average realized oil, natural gas and NGLs prices, excluding hedges.

Natural gas revenues increased by 59% from $32.4 million in the second quarter of 2016 to $51.7 million in the second quarter of 2017 as a result of a $1.04 per Mcf, or 89%, increase in average realized natural gas price, excluding hedges. The increase in average realized pricing was partially offset by a 4,458 MMcf decrease in our natural gas production, primarily due to the divestitures of oil and natural gas properties completed during 2016 and 2017.

NGLs revenues also increased 27% during the second quarter of 2017 compared to the same period in 2016 due to an $3.14 per Bbl increase in our average realized NGLs price, excluding hedges.

Oil revenues decreased by 18% from $49.9 million in the second quarter of 2016 to $41.0 million in the second quarter of 2017, primarily due to a 301 MBbls, or 24%, decrease in our oil production volumes due to the divestitures of oil and natural gas properties completed during 2016 and 2017. The decrease in our oil production volumes was partially offset by a $3.08 per Bbl increase in average realized oil price, excluding hedges. The increase in average realized oil price is primarily due to a higher average NYMEX price, which increased from $45.54 per Bbl in the second quarter of 2016 to $48.31 per Bbl in the second quarter of 2017.

Overall, our total production for the three months ended June 30, 2017 decreased by 15% on an Mcfe basis compared to the same period in 2016. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 17%, 68% and 15%, respectively, of our production during the three months ended June 30, 2017 compared to 19%, 69% and 12%, respectively, of our production during the same period in 2016.

Hedging and Price Risk Management Activities

During the three months ended June 30, 2017, we recognized a $12.9 million net loss on commodity derivative contracts. Our hedging program historically helped mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and we pay the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because our hedges are currently not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected in our 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 decreased by $1.7 million to $36.8 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016, mainly due to a $0.9 million decrease in lease operating expenses related to the divestiture of oil and natural gas properties in the SCOOP/STACK area in Oklahoma completed during 2016 and our other smaller divestitures in 2016 and 2017. In addition, we had a decrease of $0.8 million in maintenance and repair expenses on existing wells and lower lease operating expenses as a result of cost reduction initiatives including price negotiations with field vendors.

Depreciation, depletion, amortization, and accretion decreased by approximately $13.5 million to $25.3 million for the three months ended June 30, 2017 from approximately $38.8 million for the three months ended June 30, 2016, primarily 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.

An impairment of oil and natural gas properties of $157.9 million was recognized during the quarter ended June 30, 2016 as a result of a decline in oil and natural gas prices at the measurement date, June 30, 2016. The second quarter 2016 impairment was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. There was no ceiling test impairment during the three months ended June 30, 2017.

non-cash compensation expense for the three months ended June 30, 2017 decreased by $0.1 million as compared to the same period in 2016.

Other Income and Expense

Interest expense decreased to $13.8 million for the three months ended June 30, 2017 from $23.9 million for the three months ended June 30, 2016 primarily due to lower average outstanding debt under our Reserve-Based Credit Facility during the three months ended June 30, 2017 compared to the same period in 2016. In addition, we discontinued recording interest on debt classified as liabilities subject to compromise as of the Petition Date.

Reorganization Items

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results of operations. Reorganization items includes expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the Senior Notes, and are included in reorganization items as we believe these debt instruments will be impacted by the Chapter 11 Cases. Claims for non-performance of executory contracts include accrued and unpaid amounts representing our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases. Reorganization items totaled $53.2 million for the three months ended June 30, 2017. See Note 2 to the consolidated financial statements for further details.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Revenues

Oil, natural gas and NGLs sales increased $50.7 million to $225.6 million during the six months ended June 30, 2017 as compared to the same period in 2016. The key oil, natural gas and NGLs revenue measurements were as follows:



	Six Months Ended				Percentage Increase / (Decrease)
	June 30,
	2017 ^(a)		2016 ^(a)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	43.78	$	32.82	33	%
Natural Gas (Price/Mcf)	$	2.32	$	1.23	89	%
NGLs (Price/Bbl)	$	18.00	$	10.24	76	%
Average realized prices, including hedges:
Oil (Price/Bbl)	$	43.79	$	51.05	(14	)%
Natural Gas (Price/Mcf)	$	2.32	$	2.87	(19	)%
NGLs (Price/Bbl)	$	18.00	$	11.85	52	%
Average NYMEX prices:
Oil (Price/Bbl)	$	50.11	$	39.20	28	%
Natural Gas (Price/Mcf)	$	3.24	$	2.03	60	%
Total production volumes:
Oil (MBbls)	1,957		2,608		(25	)%
Natural Gas (MMcf)	47,022		56,211		(16	)%
NGLs (MBbls)	1,710		1,954		(12	)%
Combined (MMcfe)	69,020		83,585		(17	)%
Average daily production volumes:
Oil (Bbls/day)	10,811		14,331		(25	)%
Natural Gas (Mcf/day)	259,788		308,852		(16	)%
NGLs (Bbls/day)	9,445		10,737		(12	)%
Combined (Mcfe/day)	381,327		459,256		(17	)%


(a)	During the six months ended June 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)	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 increase in oil, natural gas and NGLs sales during the six months ended June 30, 2017 compared to the same period in 2016 was due primarily to the increase in average realized oil, natural gas and NGLs prices. Oil revenues remained relatively flat at $85.7 million for the six months ended June 30, 2017 compared to the same period in 2016, as a result of a $10.96 per Bbl, or 33%, increase in average realized oil price, excluding hedges, but offset by a 651 MBbls, or 25%, decrease in our oil production volumes. The increase in average realized oil price is primarily due to a higher average NYMEX price, which increased from $39.20 per Bbl in the first six months of 2016 to $50.11 per Bbl during the first six months of 2017. Natural gas revenues increased by 58% from $69.3 million in the first six months of 2016 to $109.2 million in the first six months of 2017 as a result of a $1.09 per Mcf, or 89%, increase in average realized natural gas price, excluding hedges. The increase in price was partially offset by a 9,189 MMcf decrease in our natural gas production. NGLs revenues also increased 54% during the first six months of 2017 compared to the same period in 2016 due to a $7.76 per Bbl increase in our average realized NGLs price, excluding hedges, offset by a 244 MBbls decrease in NGLs production volumes. Overall, our total production for the six months ended June 30, 2017 decreased by 17% on an Mcfe basis compared to the same period in 2016 primarily due to the divestitures of oil and natural gas properties completed during 2016 and 2017. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 17%, 68% and 15%, respectively, of our production during the six months ended June 30, 2017 compared to 19%, 67% and 14%, respectively, of our production during the same period in 2016.

Hedging and Price Risk Management Activities

During the six months ended June 30, 2017, we recognized a $12.9 million net loss on commodity derivative contracts. Our hedging program is intended to help 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 decreased by $5.5 million to $75.3 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, mainly due to a $1.7 million decrease in lease operating expenses related to the divestiture of oil and natural gas properties in the SCOOP/STACK area in Oklahoma completed during 2016 and all our other divestitures completed in 2016 and 2017. In addition, we also have a decrease of $3.8 million in maintenance and repair expenses on existing wells and lower lease operating expenses as a result of cost reduction initiatives including price negotiations with field vendors.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state or county and are based on the value of our reserves. Production and other taxes increased by $1.1 million for the six months ended June 30, 2017 as compared to the same period in 2016 primarily due to higher wellhead revenues as a result of the increase in our average realized pricing. As a percentage of wellhead revenues, production, severance and ad valorem taxes decreased from 10.4% for the six months ended June 30, 2016 to 8.5% for the six months ended June 30, 2017. The percentage was lower during the six months ended June 30, 2017 primarily due to the true-up of production and ad valorem taxes from prior periods based on actual tax assessments.

Depreciation, depletion, amortization, and accretion decreased by approximately $35.8 million to $51.1 million for the six months ended June 30, 2017 from approximately $86.8 million for the six months ended June 30, 2016, primarily 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 gas properties completed in 2016 and 2017.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. There was no ceiling test impairment during the six months ended June 30, 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. These expenses decreased $4.5 million to $15.0 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 primarily due to a decrease in office expenses during the first six months of 2017 as a result of contract rejections in connection with the Chapter 11 Cases. The decrease in selling, general and administrative expenses was offset by an increase of $0.1 million in non-cash compensation expense for the six months ended June 30, 2017 as compared to the same period in 2016, primarily due to phantom unit awards granted to our executives and board members in January 2017.

Other Income and Expense

Interest expense decreased to $30.3 million for the six months ended June 30, 2017 from $49.6 million for the six months ended June 30, 2016 primarily due to lower average outstanding debt under our Reserve-Based Credit Facility during the six months ended June 30, 2017 compared to the same period in 2016.

In addition, since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $14.3 million, representing interest expense from the Petition Date through June 30, 2017. We continue to accrue interest on the Reserve-Based Credit Facility and Senior Secured Second Lien Notes subsequent to the Petition Date since such interest was allowed by the Bankruptcy Court to be paid to the Lenders. During the Chapter 11 Cases, we paid all interest payments due under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest has been paid to the holders of the Senior Secured Second Lien Notes subsequent to the Petition Date.

Reorganization Items

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results of operations. Reorganization items include expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the Senior Notes, and are included in reorganization items as we believe these debt instruments will be impacted by the Chapter 11 Cases. Claims for non-performance of executory contracts include accrued and unpaid amounts representing our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases. Reorganization items totaled $80.0 million for the six months ended June 30, 2017. See Note 2 to the consolidated financial statements for further details.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with 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 June 30, 2017, our critical accounting policies were consistent with those discussed in our 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 cash flow estimates used in recording the acquisition of oil and natural gas properties and in impairment tests of oil and natural gas properties and goodwill, 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. 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.

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

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

The Bankruptcy Court has approved payment of certain prepetition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, certain utilities, insurance, surety bond premiums as well as payments to critical vendors and possessory lien vendors.

In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 Cases and expect that we may continue to incur significant professional fees and costs following our emergence from the Chapter 11 Cases. The Company believes it has sufficient liquidity to fund anticipated cash requirements through the Chapter 11 Cases for minimum operating and capital expenditures and for working capital purposes and excluding principal and interest payments on our outstanding debt. As such, the Company expects to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders approving such payments.

Cash Flow from Operations

Net cash provided by operating activities was $73.9 million during the six months ended June 30, 2017, compared to $91.6 million during the six months ended June 30, 2016. Changes in working capital increased total cash flows by $6.7 million for the six months ended June 30, 2017 and decreased total cash flows by $58.5 million in the same period in 2016. Contributing to the increase in working capital during 2017 was a $14.8 million decrease in accounts receivable related to the timing of receipts from production and a $0.4 million decrease in other assets substantially related to prepaid drilling costs actually spent during the period. The increase was offset by a $8.9 million net decrease in accounts payable, oil and natural gas revenue payable and accrued expenses and other current liabilities that resulted primarily from the timing effects of payments. 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 six months ended June 30, 2017 and 2016.

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, we primarily used fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. We monetized all of our commodity derivative contracts in

2016 but have entered into new commodity derivative contracts in June 2017. See Note 5. Price and Interest Rate Risk Management Activities in the Notes to 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 provided by investing activities was approximately $67.4 million for the six months ended June 30, 2017, compared to $244.7 million during the same period in 2016. Net cash provided by investing activities during the first six months of 2017 was primarily from $107.7 million in proceeds from the sale of oil and natural gas properties. In addition, we paid $17.9 million for the drilling and development of oil and natural gas properties and $22.3 million for deposits and prepayments related to the drilling and development of oil and natural gas properties. Net cash provided by investing activities during the six months ended June 30, 2016 primarily included $285.6 million in proceeds from the sale of oil and natural gas properties. Also during the first six months of 2016 cash used in investing activities included $28.0 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 $5.3 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 $23.0 million and $305.1 million for the six months ended June 30, 2017 and 2016, respectively. Cash used in financing activities during the six months ended June 30, 2017 primarily included $22.7 million in net repayments of our long-term debt. Net cash used in financing activities during the six months ended June 30, 2016 included $283.7 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

Acceleration of Debt Obligations

The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Old Second Lien Notes, all of which we describe in further detail below. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures were stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures were subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under our prepetition Reserve-Based Credit Facility and Senior Secured Second Lien Notes were reclassified as current liabilities in the consolidated balance sheet as of June 30, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. These amounts have not been classified as liabilities subject to compromise as we believe the value of the underlying assets provides sufficient collateral to satisfy such obligations. In addition, the unsecured obligations under our Senior Notes due in 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017.

We accelerated the amortization of the remaining debt issue discount of $12.8 million and debt issue costs of $3.6 million associated with the Senior Notes due 2019 and Senior Notes due 2020, fully amortizing those amounts as of the Petition Date. We entered into a restructuring agreement with the Lenders under our Reserve-Based Credit Facility, along with the Restructuring Support Agreement with certain holders of the Senior Secured Second Lien Notes, which was approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of the remaining debt issue costs related to the Reserve-Based Credit Facility and Senior Secured Second Lien Notes.

Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of June 30, 2017. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $14.3 million, representing interest expense from the Petition Date through June 30, 2017. We continued to accrue interest on the Reserve-Based Credit Facility and Old Second Lien Notes subsequent to the Petition Date since such interest was allowed by the Bankruptcy Court to be paid to the Lenders.. During the Chapter 11 Cases, we paid all interest payments due under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest was paid to the holders of the Old Second Lien Notes subsequent to the Petition Date.

Senior Secured Reserve-Based Credit Facility

The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and a borrowing base of $1.1 billion (the “Reserve-Based Credit Facility”). As of June 30, 2017 there were approximately $1.2 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $148.9 million under the Reserve-Based Credit Facility.

Letters of Credit

At June 30, 2017, we have 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 is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with marketing counterparties.

8.375% Senior Notes Due 2019

At June 30, 2017, we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger.

7.875% Senior Notes Due 2020

At June 30, 2017, we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 were the Predecessor and Successor.

7.0% Senior Secured Second Lien Notes Due 2023

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Old Second Lien Notes”) to certain eligible holders of our outstanding Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders.

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million during 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 included in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

Lease Financing Obligations

On October 24, 2014, as part of acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin (the “Piceance Acquisition”), 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%.

Off-Balance Sheet Arrangements

At June 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 June 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	$	795	$	1,670	$	—	$	—	$	—	$	—	$	2,465
Asset retirement obligations ⁽¹⁾	5,022		6,758		7,095		7,450		7,823		235,266		269,413
Derivative liabilities	3,728		7,560		3,643		2,066		—		—		16,997
Reserve-Based Credit Facility ⁽²⁾⁽³⁾	1,248,795		—		—		—		—		—		1,248,795
Senior Notes and interest ⁽³⁾⁽⁴⁾	526,600		—		—		—		—		—		526,600
Operating leases	613		1,202		1,149		1,136		1,169		5,707		10,976
Development commitments ⁽⁵⁾	13,351		—		—		—		—		—		13,351
Firm transportation agreements ⁽⁶⁾	760		1,009		820		410		—		—		2,999
Lease financing obligations ⁽⁷⁾	2,721		5,442		5,442		4,359		1,278		—		19,242
Other future obligations	234		468		308		—		—		—		1,010
Total	$	1,802,619	$	24,109	$	18,457	$	15,421	$	10,270	$	240,973	$	2,111,848


(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 7. Asset Retirement Obligations of the Notes 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)

As previously discussed, the commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020, and our Old Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility and Old Second Lien Notes were reclassified as current liabilities, and our unsecured obligations under our Senior Notes due 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017.

(4)

Consists of the Senior Notes due 2019, the Senior Notes due 2020, the Old Second Lien Notes and the related interest thereon. Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date.


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


(6)	Represents transportation demand charges. Please read Note 8. Commitments and Contingencies of the Notes to the Consolidated Financial Statements for additional information regarding our firm transportation agreements.


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


•	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;


•	Texas margin taxes;


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


•	Reorganization items;


•	Transaction costs incurred on 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 unitholders.

Adjusted EBITDA is a significant performance metric used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rates. Adjusted EBITDA is also 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 Reserve-Based 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.

For the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, Adjusted EBITDA attributable to Vanguard unitholders decreased 42%, from $199.5 million to $115.4 million. The following table presents a reconciliation of consolidated net loss to Adjusted EBITDA (in thousands):



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Net loss attributable to Vanguard unitholders	$	(53,867	)	$	(260,789	)	$	(62,791	)	$	(406,072	)
Add: Net income (loss) attributable to non-controlling interests	(5		)	40			12			64
Net loss	$	(53,872	)	$	(260,749	)	$	(62,779	)	$	(406,008	)
Plus:
Interest expense	13,832			23,932			30,273			49,636
Depreciation, depletion, amortization, and accretion	25,328			38,786			51,056			86,839
Impairment of oil and natural gas properties	—			157,894			—			365,658
Change in fair value of commodity derivative contracts ^(a)	12,875			133,780			12,875			171,253
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period ^(a)	—			823			—			1,699
Fair value of derivative contracts acquired that apply to contracts settled during the period ^(a)	—			3,866			—			6,375
Net (gains) losses on interest rate derivative contracts ^(b)	—			2,135			(30		)	6,825
Gain on extinguishment of debt	—			—			—			(89,714		)
Net loss on acquisition of oil and natural gas properties	—			1,665			—			1,665
Texas margin taxes	(436		)	(699		)	(792		)	(2,634		)
Compensation related items	2,456			2,578			5,086			4,975
Reorganization items	53,221			—			79,967			—
Transaction costs incurred on acquisitions, mergers and divestitures	—			2,779			—			3,123
Adjusted EBITDA before non-controlling interest	53,404			106,790			115,656			199,692
Adjusted EBITDA attributable to non-controlling interest	(116		)	(116		)	(232		)	(232		)
Adjusted EBITDA attributable to Vanguard unitholders	$	53,288		$	106,674		$	115,424		$	199,460


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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Net cash settlements received on matured commodity derivative contracts	$	—		$	69,859		$	7		$	142,476
Change in fair value of commodity derivative contracts	(12,875		)	(133,780		)	(12,875		)	(171,253		)
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period	—			(823		)	—			(1,699		)
Fair value of derivative contracts acquired that apply to contracts settled during the period	—			(3,866		)	—			(6,375		)
Net losses on commodity derivative contracts	$	(12,875	)	$	(68,610	)	$	(12,868	)	$	(36,851	)


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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017			2016
Cash settlements paid on interest rate derivative contracts	$	—	$	(2,123	)	$	(95	)	$	(4,727	)
Change in fair value of interest rate derivative contracts	—		(12		)	125			(2,098		)
Net gains (losses) on interest rate derivative contracts	$	—	$	(2,135	)	$	30		$	(6,825	)

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 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 Reserve-Based 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 85% of projected oil and natural gas production up to a 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, the Company monetized substantially all of our outstanding price commodity and interest rate hedges for total proceeds of approximately $54.0 million. The Company used the net proceeds from the hedge settlements to make deficiency payments under its Reserve-Based Credit Facility. In June 2017, we entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production, commencing with August 2017 production volumes.

At June 30, 2017, the fair value of commodity derivative contracts was a liability of approximately $12.9 million, of which $4.7 million settles during the next twelve months.

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



	August 1 -December 31, 2017		Year 2018		Year 2019		Year 2020
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu)	22,950,000		48,800,000		20,637,500		11,895,000
Fixed Price ($/MMBtu)	$	3.12	$	3.02	$	2.86	$	2.79
Collars:
Notional Volume (MMBtu)	—		—		4,125,000		5,490,000
Floor Price ($/MMBtu)	$	—	$	—	$	2.60	$	2.60
Ceiling Price ($/MMBtu)	$	—	$	—	$	3.00	$	3.00



	August 1 -December 31, 2017		Year 2018		Year 2019		Year 2020
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls)	1,365,100		3,059,200		821,250		622,200
Fixed Price ($/Bbl)	$	45.20	$	46.47	$	47.42	$	48.92
Collars:
Notional Volume (Bbls)	—		—		273,750		219,600
Floor Price ($/Bbl)	$	—	$	—	$	42.50	$	42.50
Ceiling Price ($/Bbl)	$	—	$	—	$	53.60	$	56.10



	August 1 -December 31, 2017		Year 2018
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Ethane
Notional Volume (Bbls)	107,100		219,000
Fixed Price ($/Bbl)	$	10.50	$	11.55
Mont Belvieu Propane
Notional Volume (Bbls)	244,800		547,500
Fixed Price ($/Bbl)	$	24.15	$	22.16
Mont Belvieu N. Butane
Notional Volume (Bbls)	91,800		182,500
Fixed Price ($/Bbl)	$	29.40	$	27.09
Mont Belvieu Isobutane
Notional Volume (Bbls)	61,200		146,000
Fixed Price ($/Bbl)	$	29.19	$	27.41
Mont Belvieu N. Gasoline
Notional Volume (Bbls)	122,400		255,500
Fixed Price ($/Bbl)	$	41.27	$	41.69

Interest Rate Risks

At June 30, 2017, we had debt outstanding of $1.8 billion. The amount outstanding under our Reserve-Based Credit Facility at June 30, 2017 was approximately $1.25 billion 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 $1.5 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 June 30, 2017, the Company had no outstanding interest rate hedge agreements.

Counterparty Risk

At June 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 Liabilities			Long-Term Liabilities			Total Amount Due From/(Owed To) Counterparty at June 30, 2017
ABN AMRO (A+)	$	(3,825	)	$	(4,242	)	$	(8,067	)
Citibank (A+)	(841		)	(2,768		)	(3,609		)
Huntington Bank (A-)	(28		)	(1,171		)	(1,199		)
Total	$	(4,694	)	$	(8,181	)	$	(12,875	)

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 June 30, 2017 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the second 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

We are defendants in certain legal proceedings arising in the normal course of our business. We are also a party to separate legal proceedings relating to (i) our merger with LRR Energy, L.P. (the “LRE Merger Litigation”), and (ii) our exchange (the Debt Exchange) of the Senior Notes due 2020 for the Old Second Lien Notes (please read Note 4. Debt of the Notes to the Consolidated Financial Statements for further discussion). Since the filing of the Company’s 2016 Annual Report on Form 10-K, there have been no material developments with respect to the legal proceedings related to the Debt Exchange litigation.

Pursuant to 11 U.S.C. § 362, the Company’s legal proceedings were automatically stayed as to the debtors through the Effective Date. Please see Note 2. Chapter 11 Cases under Item 1. Unaudited Consolidated Financial Statements, for information regarding our Chapter 11 Cases.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our securities, please refer to Part I—Item 1A—Risk Factors in our 2016 Annual Report on Form 10-K. There have been no material changes to the risk factors set forth in our 2016 Annual Report on Form 10-K.

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

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


•	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.

With the exception of New Common Stock described in the second, fourth and sixth bullets above, New Common Stock will be issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act under Section 1145 of the Bankruptcy Code (an “1145 Exemption”). New Common Stock described in the second, fourth and sixth bullets above will be issued under the exemption from registration requirements of the Securities Act provided by Section 4(a)(2) thereof.

As of the Effective Date, there were 20.1 million shares of New Common Stock issued and outstanding.

Pursuant to the Plan, the Company will also issue the following series of Warrants pursuant to an 1145 Exemption:


•	To electing holders of Old Vanguard’s Preferred Units, three and a half year Preferred Unit New Warrants, which will be exercisable to purchase up to 621,649.49 shares of the New Common Stock as of the Effective Date, subject to dilution. The expiration date of the Preferred Unit New Warrants will be February 1, 2021, and the strike price is $44.25; and


•	To electing holders of Old Vanguard’s Common Units, three and a half year Common Unit New Warrants, which will be exercisable to purchase up to 640,875.75 shares of the New Common Stock as of the Effective Date, subject to dilution. The expiration date of the Common Unit New Warrants will be February 1, 2021, and the strike price is $61.45.

The Debtors distributed waiver election notices (the “Waiver Election Notices”) to holders of Old Vanguard’s Preferred Units and Common Units. The Company will delay the issuance of the Warrants to give such holders time to respond to the Waiver Election Notices.

A maximum of 44,220 shares of New Common Stock will be reserved to distribute to general unsecured creditors electing to have their general unsecured claims paid in New Common Stock, and will be issued thereto under an 1145 Exemption. If the elections of such general unsecured claims are found to be invalid, then ninety-seven percent (97%) of the remaining unissued shares will be issued pro rata to holders of claims arising under the Senior Notes and three percent (3%) of the remaining unissued shares will be issued pro rata to holders of Old Vanguard’s Preferred Units, in each case on account of their claims under the Plan pursuant to the 1145 Exemption.

The Company expects listing of the New Common Stock to commence on the OTCQX for the end of the third quarter of 2017.

Item 3. Defaults Upon Senior Securities

The filing of the voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code on February 1, 2017 constituted an event of default that accelerated the Company’s indebtedness under the Company’s Reserve-Based Credit Facility, its Senior Notes due 2019, Senior Notes due 2020 and its Old Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility and Old Second Lien Notes were reclassified as current liabilities, and our unsecured obligations under our Senior Notes due 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of June 30, 2017. Any efforts to enforce such obligations under the related Credit Agreement and Indentures were stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code.

In accordance with the Plan, on the Effective Date, the obligations of the Debtors with respect to the following indebtedness were cancelled and discharged:


•	Third Amended and Restated Credit Agreement dated as of September 30, 2011, by and among VNG as borrower, Citibank, N.A. as administrative agent, and the lenders party thereto;


•	The 7.0% Senior Secured Second Lien Notes due February 15, 2023, issued under the Indenture, dated as of February 10, 2016, among the Predecessor and the Successors, as issuers, the subsidiary guarantors named

therein, as guarantors, and Delaware Trust Company, as trustee, as amended, supplemented or modified from time to time;


•	Indenture, dated as of May 27, 2011, by and among Vanguard Operating, LLC (previously Eagle Rock Energy Partners, L.P. and Energy Rock Energy Finance Corp.), as issuer, the guarantors named therein, and Wilmington Trust, N.A., as trustee, relating to the Senior Notes due June 1, 2019, as amended, restated, or otherwise supplemented from time to time; and


•	Indenture, dated as of April 4, 2012, among the Predecessor and the Successor, as issuers, the subsidiary guarantors named therein, as guarantors, and UMB Bank, N.A., as trustee, relating to the 7.875% Senior Notes due April 1, 2020, as amended, supplemented or modified from time to time.

On the Effective Date, except as otherwise specifically provided for in the Plan, the obligations of the Debtors, the guarantees, the indentures relating to the Senior Notes and any other certificate, share, note, bond, indenture, purchase right, option, warrant, or other instrument or document directly or indirectly evidencing or creating any indebtedness or obligation of or ownership interest in any of the Debtors giving rise to any claim or equity interest (except as provided under the Plan), were cancelled as to the Debtors and their affiliates, and the reorganized Company and its affiliates ceased to have any obligations thereunder.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

(b) Item 407(c)(3) of Regulation S-K

On the Effective Date and pursuant to the Plan, the Company adopted the Amended and Restated Bylaws (the “Bylaws”). The Bylaws provide that a stockholder of record of the Company (“Record Stockholder”) at the time of the giving of the notice described below who is entitled to vote at an annual meeting of the stockholders and who has complied with the notice procedures described below, may nominate persons for election to the board of directors at the annual meeting.

Unless otherwise required by applicable law or the Certificate of Incorporation, from and after the date on which the Company completes a Public Listing or an IPO (as each term is defined in the Bylaws), only persons who are nominated in accordance with the following procedures shall be eligible for election as directors of the Company, except as may be otherwise provided in the instrument of designation of any series of preferred stock of the Company with respect to the right of holders of preferred stock of the Company to nominate and elect a specified number of directors of the Company, who shall be nominated as provided therein. For the avoidance of doubt, the stockholder nomination provisions in the Bylaws shall not apply prior to completion of a Public Listing or an IPO.

Nominations of persons for election to the Board of Directors shall be made only at an annual or special meeting of stockholders of the Company called for the purpose of electing directors and must be (i) specified in the notice of meeting (or any supplement or amendment thereto) and (ii) made by (A) the Board of Directors or a duly authorized committee of the Board of Directors (or at the direction thereof) or (B) made by any stockholder of the Corporation (1) who is a stockholder of record on the date of the giving of the notice provided for in the Bylaws and at the time of the meeting and is entitled to vote at such meeting and (2) who complies with the notice procedures set forth in the Bylaws.

In addition to any other applicable requirements, for a nomination to be made by a stockholder of the Company, such stockholder must have given timely notice thereof in proper written form to the Secretary. To be timely, a stockholder’s notice to the Secretary must be delivered to or mailed and received by the Secretary at the principal executive office of the Corporation: (i) in the case of an annual meeting of the stockholders of the Corporation, no fewer than ninety (90) nor more than one hundred twenty (120) days prior to the first (1st) anniversary of the immediately preceding annual meeting; provided, however, that in the event that no annual meeting was held in the previous year or the annual meeting is called for a date that is not within thirty (30) days before or after such anniversary date, notice by the stockholder to be timely must be so received not later than the close of business on the tenth (10th) day following the day on which notice of the date of the annual meeting was mailed or public announcement of the date of the annual meeting was made, whichever occurs first, and (ii) in the case of a special meeting of stockholders of the Company called for the purpose of electing directors, not less than sixty (60) days prior

to the meeting; provided, however, that in the event that less than seventy (70) days’ notice of the date of the meeting is given or made to stockholders, notice by the stockholder to be timely must be so received not later than the close of business on the tenth (10th) day following the earlier of the day on which such notice or public announcement of the date of the meeting was mailed or made (as applicable). Notwithstanding anything to the contrary in the immediately preceding sentence, in the event that the number of directors to be elected to the Board of Directors is increased, a stockholder’s notice required by the Bylaws shall also be considered timely, but only with respect to nominees for any new positions created by such increase and only if otherwise timely notice of nomination for all other directorships was delivered by such stockholder in accordance with the requirements of the immediately preceding sentence, if it shall be delivered to the Secretary at the principal executive office of the Company not later than the close of business on the tenth (10th) day following the day on which notice to the stockholders of the Company was given or public announcement was made by the Company naming all of the nominees for director or specifying the size of the increase in the number of directors to serve on the Board of Directors, even if such tenth (10th) day shall be later than the date for which a nomination would otherwise have been required to be delivered to be timely. In no event shall the public announcement of an adjournment or postponement of an announced meeting commence a new time period (or extend any time period) for the giving of a stockholders notice as provided in the Bylaws.

To be in proper written form, a stockholder’s notice to the Secretary pursuant must set forth (i) as to each person whom the stockholder of the Company proposes to nominate for election as a director, (A) the name, age, business address, and residence address of such person, (B) the principal occupation or employment of the person, (C) the class or series and number of shares of capital stock of the Company which are directly or indirectly (including through any derivative arrangement) owned beneficially or of record by the person, and (D) any other information relating to the person that would be required to be disclosed in a proxy statement or other filing required to be made in connection with a solicitation of proxies for an election of directors pursuant to the Exchange Act and the rules and regulations promulgated thereunder if the Company were a reporting company under the Exchange Act, and (ii) as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the director nomination is made (A) the name and address of such stockholder, as they appear on the Company’s books, and of such beneficial owner; (B) the class or series and number of shares of capital stock of the Company which are owned (1) beneficially and (2) of record by such stockholder and by such beneficial owner, (C) a description of all arrangements or understandings between such stockholder or such beneficial owner and any other person or entity (including, without limitation, their names) in connection with the ownership of the capital stock of the Company and the nomination of such nominee(s), and any material interest of such stockholder or such beneficial owner in such nomination(s), (D) whether either such stockholder or beneficial owner intends to deliver a form of proxy to holders of the Company’s voting shares to elect such nominee or nominees, (E) a representation that the stockholder giving the notice is a holder of record of stock of the Company entitled to vote at such meeting and that such stockholder intends to appear in person or by proxy at the meeting to nominate the persons named in its notice and (F) if the Company is then subject to Section 14(a) of the Exchange Act, any other information relating to such stockholder and beneficial owner, if any, required to be disclosed in a proxy statement or other filing required to be made in connection with a solicitation of proxies for an election of directors pursuant to the Exchange Act and the rules and regulations promulgated thereunder. Such notice must be accompanied by a written consent of each proposed nominee to be named as a nominee and to serve as a director if elected. The Company may require any nominee to furnish such other information (which may include meeting to discuss the information) as may reasonably be required by the Company to determine the eligibility of such nominee to serve as a director of the Company.

If the chairman of a meeting of the stockholders of the Company determines that a nomination was not made in accordance with the foregoing procedures, the chairman of the meeting shall declare to the meeting that the nomination was defective and such defective nomination shall be disregarded.

Nothing in the Bylaws shall be deemed to affect any rights of the holders of any series of preferred stock of the Company to elect directors pursuant to any applicable provisions of the Certificate of Incorporation.

Item 6. Exhibits

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

EXHIBIT INDEX



Exhibit No.	Exhibit Title	Incorporated by Reference to the Following
2.1	Second Amended Chapter 11 Joint Plan of Reorganization of Vanguard Natural Resources, LLC, et al., dated May 31, 2017.	Exhibit 2.1 to Form 8-K filed June 8, 2017 (File No. 001-33756)
10.1	Restructuring Support Agreement, dated as of February 1, 2017, reflecting amendments implemented by Amendment dated May 23, 2017, among the Company, the Restructuring Support Parties, and the Commitment Parties thereto.	Exhibit 10.1 to Form 8-K filed June 8, 2017 (File No. 001-33756)
10.2	Amended and Restated Backstop Commitment Agreement, dated May 23, 2017, reflecting amendments implemented by Amendment dated May 23, 2017, among the Company, the Restructuring Support Parties, and the Commitment Parties thereto	Exhibit 10.2 to Form 8-K filed June 8, 2017 (File No. 001-33756)
10.3	Amended and Restated Equity Commitment Agreement, dated as of May 23, 2017, among the Company and the Investors party thereto	Exhibit 10.3 to Form 8-K filed June 8, 2017 (File No. 001-33756)
10.4	Amended and Restated Purchase and Sale Agreement between Vanguard Operating, LLC as Seller, and OXY USA INC., as Buyer Dated March 20, 2017.	Filed herewith
10.5	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	Exhibit 10.1 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.6	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	Exhibit 10.2 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.7	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	Exhibit 10.3 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.8	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.	Exhibit 10.4 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.9	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	Exhibit 10.5 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.10	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	Exhibit 10.6 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.11	Registration Rights Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc. and certain parties thereto	Exhibit 10.7 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.12	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	Exhibit 10.8 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.13	Second Amended and Restated Employment Agreement of Scott W. Smith, dated August 1, 2017	Exhibit 10.9 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
10.14	Second Amended and Restated Employment Agreement of Richard A. Robert, dated August 1, 2017	Exhibit 10.10 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)



10.15	Second Amended and Restated Employment Agreement of Britt Pence, dated August 1, 2017	Exhibit 10.11 to Form 8-K15D5 filed August 2, 2017 (File No. 001-33756)
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
101.INS	XBRL Instance Document	Filed herewith
101.SCH	XBRL Schema Document	Filed herewith
101.CAL	XBRL Calculation Linkbase Document	Filed herewith
101.DEF	XBRL Definition Linkbase Document	Filed herewith
101.LAB	XBRL Label Linkbase Document	Filed herewith
101.PRE	XBRL Presentation Linkbase Document	Filed 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: August 9, 2017
		/s/ Richard A. Robert
		Richard A. Robert
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

June 30, 2017

December 31, 2016

Beginning of period

Unit-based compensation

End of period